FACULTY OF LAW

UNIVERSITY OF WESTERN AUSTRALIA

DOCTOR OF JURIDICAL SCIENCE

A REGULATORY REVIEW OF SHALE GAS AND TIGHT GAS IN WESTERN

AUSTRALIA, SOUTH AUSTRALIA AND COLORADO

SHANE HART

Bachelor of Legal Studies (Murdoch University), Bachelor of Laws (University of New

England), Graduate Diploma in Law (University of Western Australia), Graduate Diploma in

Legal Practice (College of Law), Master of Laws (University of Western Australia)

This thesis is presented in partial fulfilment of the requirements for the Doctor of Juridical

Science (University of Western Australia)

June 2018

DECLARATION

The thesis is my own composition, all sources have been acknowledged and my contribution

is clearly identified in the thesis. The thesis does not contain any work that I have published,

nor work under review for publication.

Shane Hart

19 June 2018

1

ABSTRACT

This thesis considers the regulatory frameworks that exist in Western Australia, South Australia and

Colorado for developing shale and tight gas and the reforms that can be made to Australian regulation

to overcome popular opposition to the industry. It examines the statutory provisions and best

management practices concerning land access, water use, drilling, hydraulic fracturing,

decommissioning and rehabilitation under the Petroleum and Geothermal Energy Resources Act 1967

(WA), Petroleum and Geothermal Energy Act 2000 (SA) and Oil and Gas Conservation Act (Colorado).

Colorado already has a highly developed shale and tight gas industry and may provide regulatory

lessons for Western Australia and South Australia. Australia reportedly holds 437 trillion cubic feet of

technically recoverable shale natural gas, which is the sixth largest reserve in the world. For some

years, it has been assumed that the industry would develop these resources, but there is strong

opposition. It is likely that Western Australia will continue to try to exploit shale and tight gas from

reserves in the Canning Basin in the north of the State, but a newly elected State Government has

recently implemented an executive ban on fracking in the South West, Peel and Perth metropolitan

areas. South Australia continues to exploit shale and tight gas reserves in the Cooper Basin, which is

the most prospective and commercially sustainable region for shale gas exploitation in Australia.

Notwithstanding some popular concerns about the industry, particularly in the south-east of the State,

South Australia’s Energy Minister has publicly stated that the government does not support a ban,

moratorium, social licences or any other effective veto on the exploitation of unconventional gas.

Parliamentary inquiries in Western Australia and South Australia have identified a number of key

regulatory issues: land access arrangements, public disclosure of chemicals used in hydraulic

fracturing, encouraging the use of recycling wastewater, baseline monitoring of aquifers and the

publication of data, long-term well integrity and threats of groundwater contamination, surface spills

and waste and chemical transport, and decommissioning and rehabilitation. Industry supporters argue

that proper management makes it unlikely that industry operations pose significant risks. However,

industry opponents have convinced some in government that, at least in more densely populated areas

with high value land uses, the risks are too great. This thesis identifies the best regulatory approaches

for addressing these issues, drawing particularly on the examples of Colorado’s regulation of the shale

and tight gas industries.

2

TABLE OF CONTENTS

ABSTRACT ................................................................................................... 1

ACKNOWLEDGEMENTS ......................................................................... 5

DEDICATION .............................................................................................. 6

LIST OF FIGURES ...................................................................................... 7

LEGISLATION ............................................................................................ 8

CASES ............................................................................................................ 8

LIST OF ABBREVIATIONS ...................................................................... 9

1 INTRODUCTION AND THESIS ....................................................... 11

1.1 Introduction .............................................................................................................................. 11

1.2 Social licence to operate ........................................................................................................... 13

1.3 Coal seam gas ............................................................................................................................ 14

1.4 Risk and challenges - social and environmental .................................................................... 15

1.5 Bans and moratoria .................................................................................................................. 20

1.6 Methodology – Regulatory theory and Comparative law ..................................................... 23

1.7 Legislative intent ...................................................................................................................... 33

1.8 Thesis structure ........................................................................................................................ 35

1.9 Conclusion ................................................................................................................................. 36

2 CONTEXT FOR THE COMPARATIVE REVIEW ........................ 39

2.1 Introduction .............................................................................................................................. 39

2.2 Shale gas, tight gas and water ................................................................................................. 41

2.2.1 Production stages and production methods: Drilling and fracturing ...................................... 46

2.2.2 Footprint – shale gas, tight gas and water .............................................................................. 49

2.2.3 Resource classifications and prospectivity ............................................................................. 53

2.2.4 Reserves and basins ............................................................................................................... 54

2.2.5 Water volume, its role and availability .................................................................................. 61

2.2.5.1 Volume ............................................................................................................................ 61

2.2.5.2 The role of water .............................................................................................................. 63

2.2.5.3 Water availability ............................................................................................................ 64

2.3 Literature review: Community concerns with regulatory issues ......................................... 68

2.3.1 Land Access ........................................................................................................................... 71

2.3.2 Water access and quality protection ....................................................................................... 78

2.3.3 Regulation of well technology for drilling and hydraulic fracturing ...................................... 82

2.3.4 Decommissioning and associated issues ................................................................................ 88

2.4 Conclusion ................................................................................................................................. 93

3

3 TENURE, APPROVALS AND REGULATORY APPROACHES . 96

3.1 Introduction .............................................................................................................................. 96

3.2 Mineral and petroleum ownership .......................................................................................... 97

3.3 Grant of a petroleum resource tenure .................................................................................. 100

3.3.1 Western Australia ................................................................................................................. 100

3.3.2 South Australia ..................................................................................................................... 101

3.3.3 Colorado ............................................................................................................................... 102

3.4 Indigenous land and related interests ................................................................................... 103

3.4.1 Australia ............................................................................................................................... 104

3.4.2 The United States ................................................................................................................. 108

3.5 Environmental approvals and assessment ........................................................................... 110

3.5.1 Western Australia ................................................................................................................. 110

3.5.2 South Australia ..................................................................................................................... 114

3.5.3 Colorado ............................................................................................................................... 117

3.6 Regulatory approaches .......................................................................................................... 118

3.6.1 Western Australia and South Australia – objective/risk based............................................. 119

3.6.2 Colorado – command & control and case by case permitting .............................................. 123

3.6.3 Other regulatory approaches ................................................................................................ 128

3.7 Conclusion ............................................................................................................................... 133

4 COMPARATIVE ANALYSIS OF REGULATORY ISSUES ....... 135

4.1 Land Access ............................................................................................................................ 136

4.1.1 Statutory Access – Western Australia and South Australia ...................................................... 137

4.1.2 Statutory Access – Colorado ................................................................................................ 139

4.1.3 Land access agreements – Western Australia and South Australia ...................................... 142

4.1.4 Surface use agreements - Colorado ...................................................................................... 145

4.1.5 Conclusion ........................................................................................................................... 148

4.2 Water ....................................................................................................................................... 149

4.2.1 Australia - EPBC Act ........................................................................................................... 150

4.2.2 The United States ................................................................................................................. 151

4.2.3 Western Australia ................................................................................................................. 153

4.2.4 South Australia ..................................................................................................................... 156

4.2.5 Colorado ............................................................................................................................... 158

4.2.6 Conclusion ........................................................................................................................... 163

4.3 Drilling and fracturing .................................................................................................................. 164

4.3.1 Flow-back, produced water, recycling and reuse ................................................................. 165

4.3.1.1 Western Australia and South Australia .......................................................................... 167

4.3.1.2 Colorado ........................................................................................................................ 168

4.3.2 Beneficial use ....................................................................................................................... 171

4.3.3 Well integrity – Western Australia and South Australia................................................ 172

4.3.3.1 Colorado ........................................................................................................................ 177

4

4.3.4 Underground injection ......................................................................................................... 177

4.3.4.1 Western Australia and South Australia ............................................................................. 179

4.3.5 Chemical disclosure ............................................................................................................. 181

4.3.6 Conclusion ........................................................................................................................... 188

4.4 Decommissioning and rehabilitation .................................................................................... 189

4.4.1 Western Australia - FMP, WMP and EP.............................................................................. 192

4.4.2 South Australia – SEO ........................................................................................................ 195

4.4.3 Colorado – Reclamation regulations .................................................................................... 198

4.4.4 Conclusion ........................................................................................................................... 201

5 CONCLUSION AND RECOMMENDATIONS ............................. 202

5.1 Introduction ............................................................................................................................ 202

5.2 Recommendations .................................................................................................................. 203

5.3 Summary of Key Issues .......................................................................................................... 207

Bibliography .............................................................................................. 211

5

ACKNOWLEDGEMENTS

I appreciate the support offered by my supervisors, Professor Alex Gardner and Professor John

Chandler. I was also supported by Dr Simon Robb who played an integral part in my journey

to completion. I am grateful to Sarah Costa for her editorial assistance. They all provided

insight and guidance during the writing of this thesis. There were many occasions when my

confidence declined, however, their persistence was a great help. My biggest thank you goes

to my beautiful wife Kristy who encouraged me along the way, without this support I would

not have completed this thesis.

6

DEDICATION

To my wife, Kristy and children Alexander, Jonathan and Isabella who I love and adore.

7

LIST OF FIGURES

Figure 1 Low porosity- impermeable rock to high porosity-permeable rock ....................................... 43 Figure 2 Schematic geology of natural gas resources .......................................................................... 45 Figure 3 Vertical vs Horizontal drilling ................................................................................................ 47 Figure 4 Horizontal well and Hydraulic Fracturing ............................................................................. 49 Figure 5 Size and extent of Australia’s basins...................................................................................... 57 Figure 6 Well casing and cement layers ................................................................................................ 86

8

LEGISLATION

Aboriginal Heritage Act 1972 (WA)

Aboriginal Heritage Act 1988 (SA)

Aboriginal Affairs Planning Authority Act 1972 (WA)

Aboriginal Lands Trust Act 2013 (SA)

Colorado Groundwater Management Act (Colo. Rev. Stat. § 37-90-101)

Colorado Oil and Gas Conservation Commission rules (2 CCR 404-1, et seq)

Country Areas Water Supply Act 1947 (WA)

Metropolitan Water Supply, Sewerage and Drainage Act 1909 (WA)

Native Title Act 1993 (WA)

Natural Resources Management Act 2004 (SA)

Oil and Gas Conservation Act (Colo. Rev. Stat. § 34-60-100, et seq.)

Petroleum and Geothermal Energy Resources Act 1967 (WA)

Petroleum and Geothermal Energy Act 2000 (SA)

Petroleum and Geothermal Energy Resources (Environment) Regulations 2012 (WA)

Petroleum and Geothermal Energy Resources (Resource Management and

Administration) Regulations 2015 (WA)

Petroleum and Geothermal Energy Regulations 2013 (SA)

Rights in Water and Irrigation Act 1914 (WA)

CASES

Mabo v Queensland No. 2 (1992) 175 CLR 1 (Mabo)

Getty Oil Company v. Jones, 470 S.W.2d (618 (Tex.1971)

Gerrity Oil and Gas Corp. v. Magness 923 P.2d 261 (1995)

9

LIST OF ABBREVIATIONS

AA Administrative Arrangements

ACOLA Australian Council of Learned Academies

AM Adaptive Management

CBCP Case by case permitting

CDP Comprehensive drilling plan

CSG Coal Seam Gas

COGCC Colorado Oil and Gas Conservation Commission

CDPHE Colorado Department of Public Health and Environment

C&C Command and Control

DMIRS Department of Mines and Petroleum

DoW Department of Water

DR Drilling reservation

DPC Department of State Development

DEWNR Department of Environment, Water and Natural Resources

EUR Expected Ultimate Recovery

EP Exploration Permit

EL Exploration Licence

EIR Environmental Impact Report

EPA Environment Protection Authority

EIA Energy Information Administration

FMP Field Management Plan

GAB Great Artesian Basin

GRACE Gravity Recovery and Climate Experiment

GWMA Ground Water Management Act 1963 (Colorado)

HD Horizontal Drilling

IEA International Energy Agency

MOU Memorandum of Understanding

NASA National Aeronautics and Space Administration of the U.S.A

NRMA Natural Resources Management Act 2004 (SA)

NRC Natural Resources Committee of South Australia

OBA Objective Based Approach

10

OGCA Oil and Gas Conservation Act (Colo. Rev. Stat. § 34-60-100, et

seq.)

PGERA Petroleum and Geothermal Energy Resources Act 1967 (WA)

PGEA Petroleum and Geothermal Energy Act 2000 (SA)

PP Precautionary Principle

REM Roseneath Epsilon Murteree

RBA Risk Based Approach

RiWI Act Rights in Water and Irrigation Act 1914 (WA)

SCEPA Standing Committee on Environment and Public Affairs

Western Australia

SEO Statement of Environmental Objectives

SF Self-Regulation

SLTO Social licence to operate

Tcf Trillion cubic feet

U.S. United States of America

UG Unconventional Gas

WD Well Design

WI Well Integrity

WIH Well Integrity Hazard

WMP Well Management Plan

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1 INTRODUCTION AND THESIS

In order to realise the enormous potential of shale gas, great skill, persistence,

capital and careful management of any impacts on ecosystems and related natural

resources will be required. There must also be an informed community and

transparent and effective regulations and companion codes of practice. Provided

we have all these in place (and the right rocks), shale gas could be an important

new energy option for Australia.1

1.1 Introduction

The popular opposition to the exploitation of unconventional gas (coal seam gas, shale gas,

tight gas) worldwide raises valid social and environmental questions about the sustainability

and regulatory capacity of Australian states and territories to manage any future development.

The author questions whether regulatory frameworks can be designed to address these

questions to an extent that satisfies the Australian community. There will be significant new

risks and challenges if Australian jurisdictions choose to exploit shale and tight gas.2 The thesis

will determine whether there are gaps in the regulatory regimes of Western Australia and South

Australia in terms of land access, water access and quality protection, regulation of well

technology for drilling (and hydraulic fracturing) and decommissioning and associated issues

that can be addressed by learning from Colorado and the way it regulates shale and tight gas

exploitation.

The thesis is primarily concerned with shale and tight gas in Western Australia, South Australia

and Colorado, though it will briefly discuss coal seam gas given it is an unconventional gas,

alongside shale and tight gas. One commentator argues, quite rightly, that the exploitation of

shale and tight gas in Australia has not been as controversial as other forms of mining, ‘yet’.3

1 P Cook, V Beck, D Brereton, R Clark, B Fisher, S Kentish, J Toomey and J Williams, Engineering Energy:

Unconventional Gas Production, Report for the Australian Council of Learned Academies, May 2013, p 35 at

https://acola.org.au/wp/PDF/SAF06FINAL/Final%20Report%20Engineering%20Energy%20June%202013.pd

f 2 Rahm, B, G and Riha, S, J, ‘Evolving shale gas management: water resource risks, impacts, and lessons

learned’ (2014) 16 Environ. Sci: Processes Impacts 1400, 1409 at

http://pubs.rsc.org/en/content/articlepdf/2014/EM/C4EM00018H 3 P Cook, V Beck, D Brereton, R Clark, B Fisher, S Kentish, J Toomey and J Williams, Engineering Energy:

Unconventional Gas Production, Report for the Australian Council of Learned Academies, May 2013, p 19 at

12

There is little doubt that the shale and tight gas reserves in Western Australia and South

Australia have the potential to deliver Australia ‘energy security, a cleaner energy mix and

economic growth.’4

Australia has enough natural gas, both offshore and onshore, to sustain domestic and export

markets beyond 2030.5 There are considerable onshore coal seam gas reserves in Queensland

and New South Wales, large prospective shale gas reserves in the Northern Territory, Western

Australia and South Australia and tight gas deposits in Western Australia and South Australia.6

Western Australia’s Canning Basin and South Australia’s Cooper Basin are Australia’s most

prospective basins for shale and tight gas development based on ‘the large number of wells and

seismic data; hydrocarbon discoveries; size; locality to infrastructure and market; relative ease

of locating wells and lower cost to complete and tie wells into existing pipelines.’7 Whilst the

Canning basin and Cooper basin alone are likely to be the catalyst for Australia’s next resources

boom, the arid conditions, particularly in the Canning basin and its remoteness will lead to

significant risks and challenges in terms of exploration, production and abandonment.8

The existence of a large gas deposit is meaningless, especially if communities and legislators

choose not to publicly support the regulatory regimes that are necessary for exploitation. Some

insist, quite rightly, that significant resource estimates can create unrealistic commercial

viability expectations.9 Western Australia’s Department of Mines, Industry Regulation and

Safety (DMIRS) estimate that shale and tight gas exploitation in Western Australia is five to

<https://acola.org.au/wp/PDF/SAF06FINAL/Final%20Report%20Engineering%20Energy%20June%202013.p

df 4 Natural Gas from Shale and Tight Rocks An overview of Western Australia’s Regulatory Framework

Department of Mines, Industry Resources and Safety, February 2014, pg 5 at

http://www.DMIRS.wa.gov.au/Documents/Petroleum/PD-SBD-NST-102D.pdf 5 Daniel T.B. Leather , Alireza Bahadori , Chikezie Nwaoha , David A.Wood, ‘A review of Australia’s natural

gas resources and their exploitation’ (2013) 10 Journal of Natural Gas Science and Engineering 68-88 6 Ibid. 7 Kane Rawsthorn, Shale Gas Prospectivity Potential, AWT International, Prepared for: Australian Council of

Learned Academies, 23 January 2013 at

https://acola.org.au/wp/PDF/SAF06Consultants/AWTShale%20Gas%20Prospectivity%20Potential%20Jan201

3.pdf 8 Ibid. 9 Dr Nina Triche, Unconventional Resources: Applying the World To (Western Australia), Water Management

for Shale and Tight Gas Resources, June 8-9, 2015 – Perth, Western Australia

13

ten years away due to a lack of skilled personnel, a lack of drilling rigs capable of deep

horizontal drilling and an absence of infrastructure.10

It is likely that Australia’s desire to exploit shale and tight gas will be hampered by, amongst

other things, ‘long lead times, high capital and operational costs, necessary price environments

to attract investment, and the importance of overcoming regulatory and environmental

constraints.’11 Regulatory bodies will likely face considerable hostility if they permit operators

to exploit shale and tight gas in areas where there are competing natural resources and

environmental values. Australia’s shale and tight gas regulatory regimes are ‘ever-changing,

complex, and not harmonized.’12 Some believe the Unites States ‘was caught off guard by the

shale gas revolution and [they] have been playing catch-up since.’13 For this, and other reasons,

it is vitally important for Western Australia and South Australia to learn from the United States

to ensure that regulatory frameworks are in place to address the social and environmental issues

associated with shale and tight gas exploitation.

1.2 Social licence to operate

Shale gas resources often go undeveloped in the United States, ‘not for the lack of a legal

license, but rather for the lack of a social license’.14 A social licence forces governments and

operators to protect community interests and environmental values from negative impacts

while taking advantage of any exploitation opportunities that may arise.15 Operators use a

social licence to manage socio political risk by complying with the rules imposed by regulators

10 Natural Gas from Shale and Tight Rocks An overview of Western Australia’s regulatory framework

(Department of Mines, Industry Resources and Safety, February 2014) pg 5 at

http://www.DMIRS.wa.gov.au/Documents/Petroleum/PD-SBD-NST-102D.pdf 11 Energy Source, Why U.S. Shale Gas will not be a Cookie Cutter Model [Online] (2012)

http://theenergysource.blogspot.com/2012/06/why-us-shale-will-not-be-cookie.html 12 Ozwater, Water Quality Regulations for Unconventional Gas (accessed 23 January 2017) at

www.ozwater.org/sites/all/files/ozwater/136%20SNeitzel.pdf 13 Tim Boersma and Corey Johnson, Risks and Potentials of Shale Gas Revolution, Consequences for Markets

and the Environment, (SWP Comments 39, German Institute for International and Security Studies, December

2012) pg 4. 14 Don C. Smith and Jessica M. Richards, Social Licence to Operate: Hydraulic Fracturing-Related Challenges

Facing the Oil & Gas Industry, University of Denver, Sturm College of Law, Working Paper No. 15-12, 2015,

pg 2 at http://papers.ssrn.com/sol3/papers.cfm?abstract_id=2591988 15Simon Robb, A Best Practice Regulatory Proposal for Shale Gas Production, Doctor of Juridical Science

thesis, The University of Western Australia, 2014, pg 65.

14

and the community.16 The licence is a continuing social contract that sanctions a project from

start to finish.17 A social licence stems from a society’s view that operators have ongoing

public acceptance and approval.18

A social licence to operate can be theorised as a goal or set of rules that should be pursued.19

It is ‘not as simplistic as a company’s stamp of a community’s approval but rather it reflects an

ongoing and negotiated process where a community objection of one element of a project does

not necessarily mean that the full support is being threatened or withdrawn.’20 A social licence

is vital for operators, given that the failure to obtain one can result in ongoing conflict and

dispute with local communities.21 A social licence to operate is, in many ways, a risk

management tool. If an operator can gauge its social licence, it can assess the level of risk

linked to a project and take measures to reduce it.22 This thesis has chosen not examine social

licence to operate in specific detail, save to say that it is important for the reader to have a basic

understanding of the concept which underlies the need for regulatory change in Australia.

1.3 Coal seam gas

The Standing Council on Energy and Resources published a national regulatory framework for

natural gas from coal seams in 2013.23 The Standing Council stated that a number of the

approaches promoted in the coal seam gas framework may be appropriate for shale and tight

16 Claire Richert, Abbie Rogers, & Michael Burton, ‘Measuring the Extent of a Social License to Operate: The

Influence of Marine Biodiversity Offsets in the Oil and Gas Sector in Western Australia’ (2015) 42 Resources

Policy 121, 121 17 Damien Giurco, et. al., ‘Responsible Mineral and Energy Futures: Views at the Nexus’ (2014) 84 Journal of

Cleaner Production 327 18 Robert G. Boutilier & Ian Thomson, ‘Modelling and Measuring the Social Licence to Operate: Fruits of a

Dialogue Between Theory and Practice’ (2011) International Mine Management ; Richard Parsons, Justine

Lacey, & Kieren Moffat, ‘Maintaining Legitimacy of a Contested Practice: How the Minerals Industry

Understands its “Social License to Operate”’ (2014) 41 Resources Policy 83, 84 19 Jason Prno & D. Scott Slocombe, ‘Exploring the origins of “social license to operate” in the mining sector:

Perspectives from governance and sustainability theories’ (2012) 37 Resources Policy 346, 347; Claire

Richert, Abbie Rogers, & Michael Burton, ‘Measuring the Extent of a Social License to Operate: The

Influence of Marine Biodiversity Offsets in the Oil and Gas Sector in Western Australia’ (2015) 42 Resources

Policy 121, 121 20 Justine Lacey, Richard Parsons, & Kieren Moffat, Exploring the concept of a Social License to Operate in the

Australian Minerals Industry, CSIRO 7 (2012), (accessed 1 January 2018) <

https://publications.csiro.au/rpr/download?pid=csiro:EP125553&dsid=DS3> 21 Evan J. House, ‘Fractured Fairytales: The Failed Social License for Unconventional Oil and Gas

Development’ (2013) 13 WYO. L. Rev. 5, 51 22 Above, note 17. 23 The National Harmonised Regulatory Framework for Natural Gas from Coal Seams 2013, Standing Council

on Energy and Resources at http://www.scer.gov.au

15

gas.24 The framework deals with, amongst other issues, well integrity, water management,

hydraulic fracturing and chemical use.25 These are all issues that require management in the

context of shale and tight gas exploitation. Norton Rose Fulbright argue that, whilst there is

no prospect of the coal seam gas framework being extended to shale gas, it is reasonable to

expect that a corresponding harmonisation process may be implemented for shale and tight gas,

with some of the recommendations in the coal seam gas framework informing the process.26

The framework certainly has the capacity to influence the broader unconventional gas sector.27

The Standing Council on Energy and Resources insists that shale and tight gas jurisdictions

can benefit from the framework, particularly in terms of produced water management, aquifer

and ecosystem contamination, site remediation and well failure.28 While some of the

approaches in the coal seam gas framework may be suitable for shale and tight gas exploitation

there has been no consideration of its transferability to date. Furthermore, there has been no

assessment of how far we may be able to read across from coal seam gas issues to shale and

tight gas. This thesis focuses on the shale and tight gas industry and does not attempt a detailed

analysis of how much of the coal seam gas framework may apply to the shale and tight gas

industry.

1.4 Risk and challenges - social and environmental

There are significant risks and challenges, both social and environmental, linked to shale and

tight gas exploitation and the topic often prompts its opponents to use words like unsafe, risky,

harmful, stressful, offensive and worrying.29 Many in the community, particularly landowners

are extremely concerned about the potential for groundwater contamination, fluid spillage,

heavy vehicle traffic, and noise and property damage.30 There is also increased scrutiny from

24 Ibid. 25 Ibid. 26 Norton Rose Fulbright, Shale gas handbook, A quick-reference guide for companies involved in the

exploitation of unconventional gas resources, June 2015 at http://www.nortonrosefulbright.com/files/norton-

rose-fulbright-shale-gas-handbook-108992.pdf 27 Ibid. 28 Above, note 24. 29 Hydraulic Fracturing: Unsafe, Unregulated, Public Citizen, Protecting Health, Safety and Democracy,

(accessed 6 June 2018), < https://www.citizen.org/our-work/climate-and-energy/hydraulic-fracturing-unsafe-

unregulated> 30 ERCB Report 2011-A: Unconventional Gas Regulatory Framework - Jurisdictional Review, pp 5-7 at

https://www.aer.ca/documents/reports/r2011-A.pdf

16

the media and the public and more regulatory attention is being given to the potential for aquifer

contamination.31

The risks and challenges primarily, but not exclusively, relate to well spacing; hydraulic

fracturing; water management; landowner/public concerns; environmental issues; regulatory

processes; and information collection and dissemination.32 There are significant concerns

about the amounts of water required to carry out hydraulic fracturing, most of which is surface

or groundwater.33 There can be land use issues with transporting water (by truck and/or

pipelines), on-site contamination and waste water disposal.34 The exploitation of shale and

tight gas has drawn considerable attention to the cumulative effect of infrastructure and water

and large multi well pads, particularly in the United States, constantly operating.35

There are concerns with assessment and approval processes, debate about whether older

regulatory regimes contemplate the cumulative impacts of shale and tight gas exploitation,

whether there are adequate systems in place to manage water issues and the potential impact

of hydraulic fracturing operations on nearby wellbores and shale and tight gas operations.36

Some industry commentators are concerned with data collection and question whether data

from conventional reservoirs has any relevance to shale and tight gas exploitation.37 Data

collection is highly contentious given it is costly and some argue that operators are inclined to

suppress certain information.38

In the United States, communities are gravely concerned about ‘degradation of or stress on

water resources; road damage and increased truck traffic; threats to health; and changes in

quality of life, including the influx of large numbers of new residents and workers associated

with boomtowns.’39 One of the most vocal groups in Colorado is based in Erie, a suburb north

31 Id at 5 32 Ibid 33 Ibid 34 Ibid. 35 Ibid. 36 Ibid. 37 Id at 7 38 Ibid 39 Austin Shaffer, Skylar Zilliox & Jessica Smith ‘Memoranda of understanding and the social licence to operate

in Colorado’s unconventional energy industry: a study of citizen complaints’ (2017) 35:1 Journal of Energy &

Natural Resources Law, 69, 73

17

of Denver. The group, commonly known as ‘Erie Rising’, is made up of local mothers who

are considered anti-development.40 Erie Rising is mainly concerned about a ‘fear of pollution

and health hazards for their children attending an elementary school located 1,500 feet from a

proposed drilling site’.41 The total number of complaints in Erie (between 2010-14) was fifty

nine and related to, amongst other things, water quality, land and property damage, land

reclamation, well pad grading and aesthetics.42

Western Australia’s Standing Committee on Environment and Public Affairs received a

submission as part of its ‘Inquiry into the Implication for Western Australia of Hydraulic

Fracturing for Unconventional Gas’ stating that ‘we can live without gas; we cannot live

without clean water...A big NO to fracking from me, for my grand children’s wellbeing and

the future of our planet’.43 Another argued that the ‘devastation and degradation caused to

large areas of America should be a very strong warning to Australia before we even

contemplate such a dangerous mining practice here’.44 Moreover, ‘anyone giving support to

these (often overseas-owned) mining companies will be responsible for any ill effects on the

health of Australia’. 45 They continued that ‘we are kept in the dark about these matters, but I

think the Australian public has learned from events in the U.S and will not tolerate such

dangerous and scientifically-unproved practices to go ahead on our soil’.46

South Australia’s Natural Resources Committee ‘Inquiry into Unconventional Gas (Fracking)

in the South East of South Australia’ received a submission stating that ‘fracking has no place

on this planet, it leads to polluted water aquifers and water catchments…it pollutes our drinking

water and makes the locals sick! Oil, Coal and Gas are dying resources that should be left in

the ground’.47 Another submission argued that ‘fracking has a wide range of risks &

disadvantages, including contamination of ground water & surrounding landscapes &

40 Id at 70. 41 Ibid. 42 Id at 79. 43 Mary Sturmer, Submission, Inquiry into the Implications for W.A. of Hydraulic Fracturing for

Unconventional Gas, 18 August 2013 44 Eileen Whitehead, Submission, Inquiry in the Implications for W.A. of Hydraulic Fracturing for

Unconventional Gas, 11 September 2013 45 Ibid. 46 Ibid. 47 Justin, email sent to Patrick Dupont, Inquiry into Unconventional Gas and Fracking in SE of SA, 19 January

2015

18

farmlands & air quality…it would appear that such risks will not be effectively controlled &

regulated by existing legislation or the bodies & departments to do such a task’.48

The Natural Resources Committee received submissions from citizens who felt that there was

a ‘high likelihood of ground water contamination, adverse impacts on landscape, adverse

effects on agriculture, direct adverse environmental damage from drilling and fracking

operations’.49 One particular submission concluded that ‘it is a silly (damn fool) thing to do

for short term gain for the fossil fuel industry which should be rapidly phased out and replaced

by renewable energy, including vehicles which run on renewable resources’.50 Another

submission stated that there is ‘potential for water contamination caused by spills, leaks,

chemicals and accidents, potential for well integrity failure due to finite lifespan of cement and

steel, potential for industrialisation of landscape, unconventional gas fracking is as yet

unproven technology…’.51

The International Energy Policy Institute argues that some jurisdictions regulate the shale gas

industry ‘with more success and openness than others.’52 The Policy Institute insist that, for

Australia to reach its shale and tight gas potential, its regulatory regimes should be reviewed

and changed to provide a greater degree of ‘clarity, transparency and community

engagement.’53 According to the Australian Council of Learned Academies (ACOLA) the

development of best practice mechanisms assist in minimising the risks association with

exploitation.54 These practices have been described as ‘state-of-the-art mitigation measures

applied to oil and natural gas drilling and production to help ensure that energy development

48 Joy Mayberry, email to Patrick Dupont, Inquiry into Unconventional Gas and Fracking in SE of SA, 12

January 2015 49 Burwell Dodd, email to Patrick Dupont, Inquiry into Unconventional Gas and Fracking in SE of SA, 18

January 2015 50 Ibid. 51 Darryl Brooksby, Rivoli Bay Sailing Club, submission, Inquiry into Unconventional Gas and Fracking in SE

of SA, 12 January 2015 52 UCL International Energy Policy Institute Adelaide, Australia, Shale Gas in Australia: The Policy Options,

Green Paper, October 2013, pg 4 at https://www.ucl.ac.uk/australia/files/shale-gas-in-australia-green-paper-

final 53 Ibid. 54 P Cook, V Beck, D Brereton, R Clark, B Fisher, S Kentish, J Toomey and J Williams, Engineering Energy:

Unconventional Gas Production, Report for the Australian Council of Learned Academies, May 2013, p 20,21 at

<https://acola.org.au/wp/PDF/SAF06FINAL/Final%20Report%20Engineering%20Energy%20June%202013.pd

f>

19

is conducted in an environmentally responsible manner’.55 In Colorado, they are ‘…designed

to prevent or reduce impacts caused by oil and gas operations to air, water, soil, or biological

resources, and to minimize adverse impacts to public health, safety and welfare, including the

environment and wildlife resources’.56 The question of whether best management practices

exist in Western Australia and South Australia, and to what extent, remains unanswered.

Some industry commentators argue, that regulating shale and tight gas exploitation is difficult,

since operators do not always have the capacity to absorb new regulatory requirements;

establishing where pollution emanates from can be difficult with wells, storage tanks and

wastewater impoundments geographically dispersed and numerous; there are dispersed

regulatory regimes; regulatory opposition increases transactional and political costs to

regulatory proposals and there are significant data gaps.57 ACOLA argue that there are no

major technology gaps to cause development of shale and tight gas to be deferred, but they

insist that there are significant knowledge gaps in relation to the environment that require

further research.58 While the industry may also argue that there is no justification for halting

exploitation, it is crucial that they genuinely commit to a continued discussion of the associated

risks and challenges, and contribute to developing policies that might address them. One

independent reviewer of the industry has said that the risks and challenges associated with shale

and tight gas exploitation can be controlled if robust regulatory regimes exist.59

The Northern Territory government recently concluded a Scientific Inquiry into Hydraulic

Fracturing that resolved that ‘no industry is completely without risk, and the development of

any onshore shale gas industry in the Northern Territory is no exception’.60 The Northern

Territory Inquiry concluded that ‘the challenges and risks associated with any onshore shale

55 Best Management Practices, Intermountain Oil and Gas BMP Project, (accessed 6 June 2018)

https://www.oilandgasbmps.org 56 COGCC Rules and Regulations, Definitions (100 Series) 57 Katherine E. Konschnik and Mark K. Boling, ‘Shale Gas Development: A Smart Regulation Framework’

(2014) Environmental Science & Technology A 58 Cook, P, Beck, V, Brereton, D, Clark, R, Fisher, B, Kentish, S, Toomey, J and Williams, J (2013). Securing

Australia’s Future – Engineering energy: unconventional gas production,pg 29 at

http://www.acola.org.au/index.php/projects/securing-australia-s-future/project-6 59 Allan Hawke AC, Report of the Independent Inquiry into Hydraulic Fracturing in the Northern Territory,

2014, Executive Summary, page x. 60 Scientific Inquiry into Hydraulic Fracturing in the Northern Territory, April 2018, pg 59 (accessed 5 June

2018) https://fracking.inquiry.nt.gov.au/inquiry-reports?a=494327

20

gas industry in the Northern Territory can be appropriately managed’61 by focusing on, for

example, releasing appropriate land, decommissioning, monitoring and consulting with

traditional owners.62 As far as the Northern Territory government is concerned ‘nothing is

guaranteed... and with any new industry, it is not uncommon for problems to emerge’.63 In

response to the risks and challenges associated with shale and tight gas exploitation many

governments have introduced bans and moratoria.

1.5 Bans and moratoria

Many would agree that an alternative to banning a harmful activity is regulating it.64 The

debate about whether hydraulic fracturing is safe has opened up a ‘ban’ versus ‘regulate’ divide

within the anti-fracking community.65 The conjecture about whether exploiting shale and tight

gas is safe or unsafe has not stopped the anti-fracking movement’s overall push to ban it.66 In

fact, many countries have banned hydraulic fracturing for various social, scientific and political

reasons including France, Bulgaria, Romania, Northern Ireland, Spain and Switzerland.67

The exploitation of shale gas in Colorado led to environmental concerns and a desire for greater

local control over development.68 A number of local governments prohibited hydraulic

fracturing.69 However, these were deemed to be ‘invalid and unenforceable’ by the Colorado

Supreme Court in 2016.70 In Colorado a number of Memorandum of Understanding (MOUs)

61 Id at 60 62 Ibid 63 Ibid 64 Thomas W. Merrill & David M. Schizer, ‘The Shale Oil and Gas Revolution, Hydraulic Fracturing, and

Water Contamination: A Regulatory Strategy’ (2013) Minnesota Law Review 206 65 Global Shale Gas and the Anti-Fracking Movement, Developing Union Perspective and Approaches, Working

Paper 1, Trade Unions for Energy Democracy, [June 2014], pg 11 https://unionsforenergydemocracy.ord 66 Rebbeca Burns, ‘A Fracktious Debate: Greens and divided on whether to regulate fracking or hold out for a

ban’ In these Times, 10 July 2013 67 Petrol global news, 9 countries or regions that ban fracking, (assessed 1 January 2016) at

https://petroglobalnews.com/2013/10/9-countries-or-regions-that-ban-fracking/amp 68 Austin Shaffer, Skylar Zilliox & Jessica Smith, ‘Memoranda of understanding and the social licence to

operate in Colorado’s unconventional energy industry: a study of citizen complaints’ (2017) 35:1 Journal of 69 Michael Wines, ‘Colorado Court Strikes Down Local Bans on Fracking’ The New York Times, 2 May 2016

,https://mobile.nytimes.com/2016/05/03/us/colorado-court-strikes-down-local-bans-on-fracking.html 70 Joel Minor, ‘Local Government Fracking Regulations: A Colorado Case Study’ (2014) 33 Stanford

Environmental Law Journal (SELJ) 61; Bruce Finley, ‘Colorado Supreme Court Rules State Law Trumps

Local Bans on Fracking’ Denver Post, 2 May 2016 at www.denverpost.com/2-16/05/02/colorado-supreme-

court-rules-law-trumps-local-bans-on-fracking

21

were signed between local governments and operators that enabled development to proceed

while addressing the concerns of local communities.71

In Western Australia, a submission to the Standing Committee on Environment and Public

Affairs argued that ‘given that fracking has only been in operation for 30 years in the United

States and less than ten years in the eastern Australian states, so far the subsequent social costs

seem to outweigh the benefits of the gas sourced’.72 The submission insisted that ‘due to a

contentious history on the east coast of Australia and in north America and with Western

Australia not requiring the gas reserves in the medium term, it is prudent to call a moratorium

on the industry until all the issues are resolved’.73

Western Australia’s Country Women’s Association passed a motion at their 89th State

conference ‘requesting a moratorium on gas fracking in Western Australia until it could be

proven by an independent body to be safe for the State’s underground and surface water

supply.’74 The Country Women’s Association was concerned that a large amount of water was

required to hydraulically fracture wells and maintained that ‘…there is little enforceable

regulation in WA to minimise the negative environmental impact of hydraulic fracturing of

shale gas.’75

The Parliament of Western Australia passed the Natural Gas (Canning Basin Joint Venture)

Agreement Act 2013 (WA) ‘to ratify and authorise the implementation of an agreement…to

promote the natural gas exploration and development of the area of certain petroleum

exploration permits in the Canning Basin region of Western Australia’ (‘the State

Agreement’).76 The State Agreement allowed for the ‘evaluation, development and

71 Austin Shaffer, Skylar Zilliox & Jessica Smith ‘Memoranda of understanding and the social licence to operate

in Colorado’s unconventional energy industry: a study of citizen complaints’ (2017) 35:1 Journal of Energy &

Natural Resources Law 69, 69 at https://doi.org/10.1080/02646811.2016.1216696 72 David Rickson, Chairman Gingin Water Group, Submission, Inquiry into the Implications for W.A. of

Hydraulic Fracturing for Unconventional Gas,19 September 2013, (assessed 10 December 2013) 73 Ibid. 74 Anne Gething, CWA of WA, Submission, Inquiry into the Implications for W.A. of Hydraulic Fracturing for

Unconventional Gas, 15 August 2013 75 Ibid. 76 Mr Colin Barnett, Second Reading Speech, Natural Gas (Canning Basin Joint Venture) Agreement Act 2013

(WA), Extract from Hansard, Assembly, Wednesday, 8 May 2013

22

exploitation of natural gas resources in the Canning Basin’.77 In 2015, the Western Australia

government extended the key dates after being advised by Buru Energy (‘Buru’) that the

evaluation of the natural gas resources in the Canning Basin was progressing at a slower pace

than was originally anticipated.78

In 2017, the newly elected Western Australian government terminated the State Agreement

pending the outcome of a Scientific Review into Hydraulic Fracturing.79 The government also

announced that there would be a ban and moratorium on hydraulic fracturing, which covered

existing and future petroleum titles in the South-West, Peel and Perth metropolitan regions,

and a moratorium that prohibited the use of hydraulic fracturing throughout the rest of the

state.80 The future of fracking in Western Australia would be decided following a scientific

review.81

The New South Wales government imposed a moratorium on hydraulic fracturing in December

2010 (which has since been lifted); the Tasmanian government has a moratorium until 2020.82

In contrast, the South Australian government has publicly stated that it does not support a ban,

moratorium, social licence or any other veto on exploration or extraction that would undermine

the public rights (to ownership of petroleum rights).83 The Victorian Parliament banned

hydraulic fracturing and imposed a moratorium on any petroleum exploration and petroleum

production in onshore Victoria until mid-2020.84

77 Natural Gas (Canning Basin Joint Venture) Agreement Act 2013 (WA) at

http://www.slp.wa.gov.au/pco/prod/FileStore.nsf/Documents/MRDocument:24917P/$FILE/Natural%20Gas%

20(Canning%20Basin%20Joint%20Venture)%20Agreement%20Act%202013%20-%20[00-a0-

04].pdf?OpenElement 78Second Reading speech, Natural Gas (Canning Basin Joint Venture) Agreement Amendment Bill 2015 (WA)at

http://www.parliament.wa.gov.au/Parliament/Bills.nsf/3AD963612A77877C48257EB9000F7E60/$File/Bill14

4-1BSR.pdf 79 Premier Mark McGowan, Canning Basin agreement to be terminated, Wednesday, 29 November 2017. 80 McGowan Government implements fracking commitment,Thursday, 5 September 2017 at <

https://www.mediastatements.wa.gov.au/Pages/McGowan/2017/11/Canning-Basin-agreement-to-be-

terminated.aspx> 81 Ibid. 82 Tasmanian Government Policy Statement on Hydraulic Fracturing (Fracking) 2015 (accessed 1 May 2018),

http://dpipwe.tas.gov.au/Documents/Tasmanian%20Fracking%20Policy%20Statement_26-2-15.pdf 83 Belinda Willis, Energy Minister deals blow to anti-fracking campaign in SA’s South-East, The Advertiser, 24

May 2017. 84 Resources Amendment Legislation (Fracking Ban) Act 2017 (Victoria)

23

A Private Members bill, the Landholders’ Right to Refuse (Gas and Coal) Bill 2015, was

introduced into the Commonwealth Parliament to give landholders the right to refuse access to

their land without written authorisation and prohibit hydraulic fracturing for coal seam gas and

shale and tight gas.85 In late 2015, a Senate Committee recommended that the senate not pass

the bill.86 Throughout Australia it is apparent that there is greatest hostility to the shale and

tight gas industry in areas of higher environmental values and sensitivity. It is likely that, in

these areas, the shale and tight gas industry will never be permitted to operate. However, it is

also likely that in other areas the community will accept governmental and industry arguments

that the industry’s operations can be adequately regulated to protect social and environmental

values while exploiting the economic opportunities of shale and tight gas resources.

1.6 Methodology – Regulatory theory and Comparative law

A prominent academic with a keen interest in regulation insists that social problems and

limitations prompt regulation.87 Some believe regulation is an abstract concept used in various

different settings.88 In order to understand regulation one must ‘acknowledge that

imperfections and limitations impair decision making… and that regulation is here to stay.’89

Despite the fact that jurisdictions use different regulatory tools, ‘all are valid forms of

regulation, and none is necessarily less stringent or effective than the others’.90 The ‘promotion

of economic efficiency, environmental sustainability, morality, and the general welfare of the

public…guarantee the imperfect nature of regulation’.91

85 Senate Hansard, Senator Waters, Landholders’ Right to Refuse (Gas and Coal) Bill 2015 (Commonwealth) at

http://parlinfo.aph.gov.au/parlInfo/download/chamber/hansards/1da66012-4613-4c01-8369-

b2c1421daaaf/toc_pdf/Senate_2015_03_04_3215_Official.pdf;fileType=application%2Fpdf 86 Environment and Communications Legislation Committee inquiry into the Landholders’ Right to Refuse (Gas

and Coal) Bill 2015, pg 52. 87 Barak Orbach, What is Regulation? Regulation: Why and how the state regulates (Foundation Press, 2012) 10

http://ssrn.com/abstract=2143385 , 88 Department of Treasury and Finance, ‘Victorian Guide to Regulation (Guide, Government of Victoria,

Australia, August 2011)

http://www.dtf.voc.gov.au/CA25713E0002EF43/WebObj/VictorianGuidetoRegulationJuly2011/$File/Vicotian

GuidetoRegulationJuly2011.pdf 89 Ibid. 90 Nathan Richardson, Madeline Gottlieb, Alan Krupnick, and Hannah Wiseman, ‘The State of State Shale Gas

Regulation’, June 2013, pg 5 at http://www.rff.org/files/sharepoint/WorkImages/Download/RFF-Rpt-

StateofStateRegs_Report.pdf 91 Robert Baldwin, Martin Cave & Martin Lodge, Understanding Regulation, Theory, Strategy, and Practice

(Oxford, 2nd Edition, 2012) 4

24

Regulation usually involves government intrusion in freedom and choices.92 Some industry

commentators insist that regulation is fundamentally about controlling and managing risks.93

Those that support regulation view it as a tool governments use to exercise control over

important economic and social activities; cynics consider regulation a burden on economic

activity.94 Those who support it reject arguments of regulatory trade-offs.95 There is little doubt

that what constitutes ‘good regulation’ is a matter of opinion.96

Some scholars of regulation suggest that ‘…to regulate means to control or direct others by

rules or standards.’97 For many, ‘government regulation has connotations of a powerful

authority making people do things they would not otherwise do and generally interfering in

people’s lives in intrusive and wasteful ways’.98 Theories of regulatory development are at

their ‘most comfortable when considering the effects of a single regime on a sector or issue’.99

Governments generally avoid establishing precise, central blueprints and, instead, draft lists of

qualities they consider appropriate in a good regulatory regime.100 They also typically spread

enforcement and policymaking powers across numbers of agencies.101 Some suggest that

‘while regulation can assist with achieving the community’s objectives, it can also impose

unnecessary compliance burdens on the regulated’.102 All regulation, regardless of approach,

leads to unintended consequences, positive and negative.103

There are a number of specific regulatory approaches that are suitable for managing the

exploitation of shale and tight gas and a single regulatory approach is incapable of accounting

for all these, especially given that every approach is flawed in some way.104 One industry

commentator argues that there is no perfect regulatory model and regulatory success requires

92 Ibid 93 J Black, ‘The Role of Risk in Regulatory Processes’, in R. Baldwin, M. Cave and M. Lodge (eds), The Oxford

Handbook of Regulation (Oxford, 2010) 94 Robert Baldwin, Martin Cave & Martin Lodge, Understanding Regulation, Theory, Strategy, and Practice

(Oxford, 2nd Edition, 2012) 4 95 Frank Ackerman & Lisa Heinzerling, Priceless: On Knowing the Price or Everything and the Value of

Nothing (The New York Press, 2004 96 Above, note 87 at 37. 97 Valerie Braithwaite, Closing the gap between regulation and the community, Regulatory Theory, Foundations

and applications (ANU Press, 2017), 25 98 Ibid. 99 Robert Baldwin, Martin Cave & Martin Lodge, Understanding Regulation, Theory, Strategy, and

Practice(Oxford, 2nd Edition, 2012) 63 100 Id at 38. 101 Robert Baldwin and J. Black, ‘Decentring Regulation: The Role of Regulation and Self –Regulation in a

“Post-Regulatory World”’ (2001) Current Legal Problems 103-46 102 Simon Robb, ‘A best practice regulatory proposal for shale gas production’, 2014, 83, 85 103 Id at 84. 104 Ibid.

25

a ‘low cost, low risk regulatory system’.105 In recent times, the value of distinct approaches to

regulations has been studied, particularly in the context of environmental disasters.106

As well as commissioning its own external review,107 DMIRS often examines international and

interstate reviews and reports.108 DMIRS argue that these provide a basis upon which it

contemplates enhancements to Western Australia’s regulatory framework and inform the

industry about best practice methods.109 It has become common practice for legislators and

academics who seek to improve their legal system to look overseas, though it is certainly true

that introducing laws from other countries can fail due to contextual differences.110 As a result,

in some cases a more systematic contextual approach may be required.111 The author has

chosen to use a comparative law methodology to review the shale and tight gas regulatory

regimes of Western Australia, South Australia and Colorado. Comparative law is used to find

‘general principles of law that have international legitimacy’.112

One comparative law theorist argues that ‘comparing only legislation is risky when there is no

information available on how it works in practice, and such a limited comparison is only

acceptable for countries which are not the core of one’s comparative research.’113 To achieve

its methodological aim the thesis will compare Western Australia, South Australia and

Colorado’s legislation and regulations and refer to a number of journal articles, academic

papers, regulatory documents, government reports, industry documents, parliamentary

committee reports and government reviews.

105 Alan Hardacre, ‘Better Regulation – What is at Stake?’ (Training Paper, European Institute of Public

Administration , 2008) 3 at http://www.eipa.eu/files/repository/eipascope/20080905132115 _SCOPE2008-

2_1_AlanHardacre.pdf 106 Christel Koop and Martin Lodge, ‘What is Regulation? An interdisciplinary concept analysis’ (2017)

Regulation & Governance 95, 95 107 Tina Hunter, Regulation of Shale, Coal Seam Gas and Tight Gas Activities in Western Australia, Final, An

analysis of the capacity of the Petroleum and Geothermal Energy Act 1967 (WA) to regulate onshore gas

activities in Western Australia, July 2011 108 Submission of the Legislative Council Standing Committee on Environment and Public Affairs: “Inquiry into

the Implications for Western Australia of Hydraulic Fracturing for Unconventional Gas”, Department of Mines

and Petroleum, October 2013, Pg 5 109 Ibid. 110 Mark Van (Hoeke, 2015), ‘Methodology of Comparative Legal Research’(2015), 1-35 Law and Method 3 111 Ibid. 112 Mauro Cappelletti, ‘Comparative Law Teaching and Scholarship: Method and Objectives’ (1994) Asia

Pacific Law Review 7 113 Mark Van (Hoeke, 2015), ‘Methodology of Comparative Legal Research’(2015), 1-35 Law and Method 3

26

The same comparative law theorist insists that, sometimes, the act of ‘comparing’ is regarded

as a standalone ‘method’ known as ‘the comparative method’ without additional explanation

or specific guidelines.114 The only other ‘method’ that goes beyond this is the ‘functional

method’.115 The functional method does not just compare rules; it provides solutions to

practical problems with opposing interests.116 The functional method is based on the idea that

‘there are relatively universal human attitudes to certain situations, such as taking care of

children, respecting property rights, executing contractual obligations, compensating in one

way or another damages caused by one’s wrongful conduct, and so on.’117

Another comparative law theorist insists that the first task in the journey is to search for a social

issue, or desire, experienced by the citizens subject to the legal structures under comparative

analysis.118 The differences in the way they are legally managed does not thwart the

comparative study of such resolutions.119 The same theorist argues that, to have a significant

comparative study, ‘we need to have a societal problem shared by the various systems included

in the comparative study.’120 The thesis is underpinned by the notion that to have an important

shale and tight gas comparative study, ‘the common point of departure must be a situation in

which all the countries involved in the study have environmental problems of a common

nature.’121 As has been so articulately put before, ‘it would make no sense to include countries

in which such problems do not exist, because they are still in a pre-industrial stage of their

economic development.’122

Some jurisdictions regulate the unconventional gas industry ‘with more success and openness

than others.’123 The question of whether Colorado regulates shale and tight gas with more

success than Western Australia and South Australia remains unanswered in the current

114 Id at 8. 115 Ibid. 116 Ibid. 117 Id at 11. 118 Mauro Cappelletti, ‘Comparative Law Teaching and Scholarship: Methods and Objectives’ (1994) Asia

Pacific Law Review 2 119 Ibid. 120 Ibid. 121 Ibid. 122 Ibid. 123 UCL International Energy Policy Institute Adelaide, Australia, Shale Gas in Australia: The Policy Options,

Green Paper, October 2013, pg 4 at https://www.ucl.ac.uk/australia/files/shale-gas-in-australia-green-paper-

final

27

literature. The International Energy Policy Institute insisted that, in order for Australia to reach

its development potential, its regulatory regimes must be reviewed and changed so as to provide

a greater degree of ‘clarity, transparency and community engagement’.124 David Maloney

argues that, given the likely significance of the shale gas industry in Australia, ‘it is an

appropriate time to evaluate the existing legislation to determine whether it is fit for purpose

for shale gas exploitation or whether it lags best regulatory practice’.125 As pointed out by Mr

Maloney, ‘there has been little legislative or policy attention to shale oil and shale gas, other

than in the context of hydraulic fracturing…’126

There are four critical components to comparative methodology.127 The first requires an

evaluation of the law in a way that is clear, objective and neutral; the second is an evaluation

that is expressed in a tangible way; the third requires an evaluation of the law in operation in a

cultural context and lastly a summation of comparative observations.128 The subsequent

chapters will address each of these components. Comparing domestic law with foreign law is

highly valued in doctrinal legal research.129 It is also well known that legal practice now

involves comparative law.130

In the United States, exploiting shale and tight gas has resulted in decreased unemployment,

an increase in economic activity and has helped with energy independence.131 Many want to

know how to profitably exploit shale gas resources outside the United States.132 Despite this,

the Australia Institute argues against developing unconventional gas given ‘gas is a small

employer, unconventional gas development does not lead to cheaper gas prices, gas makes a

small contribution to the state budget, gas has serious impacts on local communities and other

industries’.133 Some have suggested that, while there is significant investment potential for

124 Ibid. 125 David AW Maloney, ‘Unconventional oil and gas in Australia: a case of regulatory lag’ (2015) 33:4 Journal

of Energy & Natural Resources Law 349, 353 126 Id at 394. 127 Edward J. Eberle, ‘The Method and Role of Comparative Law’, (2009) 8 Wash. U. Global Stud. L. Rev. 451,

457 http://openscholarship.wustl.edu/law_globalstudies/vol8/iss3/2 128 Ibid. 129 Mark Van Hoeke, ‘Methodology of Comparative Legal Research’, (2015) 1-35 Law and Method 1 130 Ibid. 131 Nicholson, Barclay and Blanson, Kadian, ‘Trends emerge on hydraulic fracturing litigation’ (2011) 109 Oil

& Gas Journal 80 132 Wang, Z. and Krupnick, A., A Retrospective Review of Shale Gas Development in the United States: What

Led to the Boom?, 2013 at http://www.rff.org/RFF/Documents/RFF-DP-13-12.pdf 133 Matt Grudnoff, Rod Campbell and Mark Ogge, Submission, The Australia Institute, Inquiry into

Unconventional Gas (Fracking), February 2015

28

unconventional gas, the ‘rapid growth elevates risks associated with environmental, social and

governance (ESG) failures given the numerous unresolved technical, regulatory and

stakeholder issues’134 associated with exploiting unconventional gas. It is in the interests of

investors that the risks and issues associated with exploiting unconventional gas are addressed

early to limit potentially negative investment impacts.135 Though it is quite difficult to

understand exactly what the essential or necessary conditions for fostering the shale gas

industry in Australia are, many commentators agree that an historic review of the United States

experience, can at least inform the conditions that assisted in this regard.136

The understanding, expertise, and experience of operators, regulators, and academics in the

United States in relation to the exploitation of shale and tight gas is extensive. Australia’s

acceptance of the comparative value of the United States is vitally important for future shale

and tight gas exploitation in Western Australia and South Australia. Major technological

advances have increased the viability of exploiting shale and tight gas with horizontal drilling

techniques increasing the accessibility of unconventional deposits.137 The use of horizontal

drilling and hydraulic fracturing triggered a natural gas boom from shale formations in the

United States and resulted in an average annual growth rate of nearly 50 percent in shale gas

production.138 Both these techniques can turn unproductive areas of the United States into

large natural gas fields.139

There is substantial comparative value in examining how Colorado regulates shale and tight

gas for various reasons. Australia and the United States have similar geological and industry

conditions.140 Dr Tina Hunter insists that Western Australia and South Australia’s petroleum

regulators are ‘professional and have the necessary experience and processes to implement best

134 Amanda Wilson, Regnan, Submission, Inquiry into the Implications for W.A. of Hydraulic Fracturing for

Unconventional Gas, 17 September 2013 135 Ibid. 136 Wang, Z. and Krupnick, A.,A Retrospective Review of Shale Gas Development in the United States: What

Led to the Boom?, 2013 http://www.rff.org/RFF/Documents/RFF-DP-13-12.pdf 137 CSIRO ‘What is Hydraulic Fracturing?’, Factsheet, 2012, CSIRO website, p. 1, viewed 5 December 2013, at

< https://www.csiro.au/en/Research/Energy/Hydraulic-fracturing/a-What-is-hydraulic-fracturing> 138 Crawford School of Public Policy, Unconventional Gas Production and Water Resources, Lessons from the

United States on better governance – a workshop for Australian government officials, 2012, pg 6 at

https://crawford.anu.edu.au/pdf/inthenews/12186-unconventional-gas-document-web-fa.PDF 139 Hobart M. King, Hydraulic Fracturing of Oil & Gas Wells Drilled in Shale, (assessed 28 June 2017) at

http://geology.com/articles/hydraulic-fracturing/ 140 EIA/ARI World Shale Gas and Shale Oil Resource Assessment, Australia, (2013), pg III-1 at

https://www.eia.gov/analysis/studies/worldshalegas/pdf/Australia_2013.pdf

29

practice in the regulation of unconventional natural gas.’141 According to Dr Simon Robb,

Western Australia’s regulatory approach ‘is not optimal but it is coherent and anticipatory.’142

The industry has changed so rapidly that Dr Robb argues that it has often outpaced the

availability of information for regulators to develop specific guidance.143 The United States

offers important insights for Western Australia and South Australia as they seek to exploit shale

and tight gas. This thesis believes Colorado represents an appropriate ‘model’ for duplication

provided ‘governance frameworks reflect domestic realities and capacities’.144

The success of the United States in exploiting natural gas has prompted investors to ramp up

efforts to exploit Western Australia and South Australia’s enormous shale and tight gas

reserves. Colorado has considerable experience exploiting shale and tight gas and was the sixth

leading producer state of natural gas in the United States in 2012.145 It also has ten of largest

natural gas fields in the United States.146

The author believes that Colorado has a regulatory regime that should be used as a regulatory

model for Western Australia and South Australia. Dr Hawke AC received a number of

submissions to his inquiry into hydraulic fracturing stating that Western Australia and South

Australia have regulatory regimes that are bench marks for identifying best practice.147 A

number of the submissions also pointed to elements of Western Australia and South Australia’s

regulatory frameworks, as well as Colorado’s, as being more appropriate.148

141 “WA DMIRS recognised as one of world’s best resource regulators” Australian Mining news release 3

November 2013 from http://miningaustralia.com.au/news/wa-DMIRS-recognised-as-one-of-world-s-best-

resources 142 Simon Robb, A Best Practice Regulatory Proposal for Shale Gas Production, The University of Western

Australia, 2014, pg 2 143 Ibid. 144 Jarvis, M, ‘Towards a Roadmap for Governance of Unconventional Gas: A Multidimensional Challenge’

(2014) 12:3 Oil, Gas & Energy Law at < https://www.ogel.org/article.asp?key=3464> (assessed 23 November

2017) 145 Colorado State University, Oil and Gas Development in Colorado – 10.639 (2014) at

http://extension.colostate.edu/topic-areas/family-home-consumer/oil-and-gas-development-in-colorado-10-

639/ 146 Colorado State University, Oil and Gas Development in Colorado – 10.639, (2014) at <

http://extension.colostate.edu/topic-areas/family-home-consumer/oil-and-gas-development-in-colorado-10-

639/> 147 Allan Hawke SC, Report of the Independent Inquiry into Hydraulic Fracturing in the Northern Territory,

(2014) at http://www.hydraulicfracturinginquiry.nt.gov.au/docs/report-inquiry-into-hydraulic-fracturing-nt.pdf 148 Ibid.

30

While the author acknowledges that there are significant differences between the three

regulatory regimes, (particularly given Colorado has a myriad of state, county, and federal

government arrangements) there is sufficient cohesion between them to make a comparative

analysis appropriate.149 This thesis is underpinned by the principle that ‘just as natural

scientists use laboratories to conduct experiments to verify their own hypotheses, comparative

law analysis acts as the laboratory for the legislator’.150 The use of a comparative law

methodology will achieve the thesis objective, that is, to improve Western Australia and South

Australia’s regulatory regimes.151

The author acknowledges that there are no guarantees that Western Australia and South

Australia have the capacity to replicate what has occurred in Colorado. However, some

industry commentators suggest that there is ‘…much merit in sharing knowledge and

experience between the United States and Australia in the development of unconventional gas

production, and building on the lessons learned in the United States could improve regulation

and governance in Australia’.152 The regulatory regime in the United States is complex.153

Some suggest that this is the result of it ‘having to ‘catch up’ to the rapid increase in shale gas

activity and the interaction between federal and state governments’.154

There is widespread concern with the use of hydraulic fracturing. Some argue that Colorado

‘is at the forefront of policy-making and public debate over the regulation of hydraulic

fracturing’.155 Colorado was the first jurisdiction in the United States to pass wide-ranging

rules dealing with the public disclosure of chemicals that are used in hydraulic fracturing.156

149 Crawford School of Public Policy, Unconventional Gas Production and Water Resources, Lessons from the

United States on better governance – a workshop for Australian government officials, 2012, pg 47 at

https://crawford.anu.edu.au/pdf/inthenews/12186-unconventional-gas-document-web-fa.PDF 150 Mauro Cappellatti, ‘Comparative Law Teaching and Scholarship: Method and Objectives’ (1994) Asia

Pacific Law Review 7 151 Mark Van Hoecke, ‘Methodology of Comparative Legal Research’ (2015), Law and Method, 2 152 Crawford School of Public Policy, Unconventional Gas Production and Water Resources, Lessons from the

United States on better governance – a workshop for Australian government officials, 2012, pg 47 at <

https://crawford.anu.edu.au/pdf/inthenews/12186-unconventional-gas-document-web-fa.PDF> 153 Simon Robb, A Best Practice Regulatory Proposal for Shale Gas Production, The University of Western

Australia, 2014, pg 2 154 Ibid. 155 Austin Shaffer, Skylar Zilliox & Jessica Smith ‘Memoranda of understanding and the social licence to

operate in Colorado’s unconventional energy industry: a study of citizen complaints’ (2017) 35:1 Journal of

Energy & Natural Resources Law 69, 70 156 Tanya Heikkila and others, ‘Understanding a Period of Policy Change: The Case of Hydraulic Fracturing

Disclosure Policy in Colorado’ (2014) 31 Review of Policy and Research 65

31

Colorado’s framework is entrenched, development is at an advanced stage and it has some of

the most restrictive regulations on oil and gas production in the United States.157 Some

industry commentators suggest that Colorado has the toughest groundwater monitoring rules,

requirements for post line testing for gas wells and restrictive stormwater rules.158

Colorado has significant experience exploiting shale and tight gas and a relatively mature state

based regulatory regime administered by the Colorado Oil and Gas Conservation Commission

(COGCC). The author believes that Western Australia and South Australia will both face the

same risks and challenges experienced by communities, politicians and industry in Colorado

though in a vastly different social and political context. One industry commentator contends,

quite correctly, that ‘there is no cookie cutter approach’ and that it is important for operators to

understand the political economy in which they operate.159

The COGCC has taken steps to address stakeholder concerns with hydraulic fracturing by

imposing additional regulatory requirements that deal with hydraulic fracturing.160 There are

key provisions in Colorado that are transferable to Western Australia and South Australia that

should be transferred as a priority. For example, Western Australia and South Australia do not

do enough to protect landowners by minimising intrusion on private land by operators. This is

often justified because both are mining states. Operators can essentially (subject to conditions)

mine anywhere except in certain restricted areas, for example, national parks and people’s

houses. In Western Australia and South Australia, landowners and operators can enter into

land access agreements that have no statutory basis. These agreements are voluntary and

drafted with reference to non-statutory guidelines. There is a statutory provision in Colorado

known as ‘reasonable accommodation’ that sets out that operators and landowners should seek

to minimise intrusion on land.

157 Stephanie Neitzel, P.E. Esq, Water Quality Regulations for Unconventional Gas Production United States

and Australia Comparison, WaterRich Advisors LLC, at <

http://www.awa.asn.au/documents/136%20SNeitzel.pdf> (assessed 20 July 2017) 158 Ibid. 159 Jarvis, M, ‘Towards a Roadmap for Governance of Unconventional Gas: A Multidimensional Challenge’,

(2014) 12:3 Oil, Gas & Energy Law < https://www.ogel.org/article.asp?key=3464> (assessed 23 November

2017) 160 COGCC Hydraulic Fracturing Rules, at https://cogcc.state.co.us/Announcements (assessed 20 June 2016)

32

The significant differences between how Western Australia, South Australia and Colorado

regulate shale and tight gas exploitation cannot simply be rationalised on the basis of the

differences in geology, hydrology, and demographics, because the regulatory issues present

different risks to local communities and industry.161 Most are nothing more than ad hoc

modifications that have occurred over decades.162 The author argues that the differences

between each of the regimes is the result of political motives, community acceptance and the

control, influence and the knowledge held by their respective regulatory agencies.

This thesis argues that Western Australia and South Australia cannot simply take a ‘wait and

see’ approach to shale and tight gas exploitation because they are in the early stages of

exploration.163 Both jurisdictions should continue to explore for, and exploit, shale and tight

gas though regulators, operators and communities must commit to a prolonged discussion of

the accompanying risks and challenges and formulate policies and introduce laws that might

address them. Each of these groups must examine the risks and impacts over time as part of

the overall exploration, production and abandonment process.

The mixture of different regulatory regimes and approaches is driven by the regulatory goals

of the respective jurisdictions and their desire to achieve them, plus the motivation of the

respective regulatory bodies and government. The United States has considerable experience,

expertise, and knowledge in producing shale and tight gas and it has been suggested that ‘in

terms of governance and regulation, the complexity of operating within state, county, and

federal government arrangements – while very different in detail – have much in common

between the United States and Australia.’164

The author argues that a considerable amount can be gained if Western Australia and South

Australia examine how Colorado regulates shale and tight gas exploitation in several key areas.

Western Australia and South Australia should modify their regulatory regimes accordingly, not

161 Nathan Richardson, Madeline Gottlieb, Alan Krupnick, and Hannah Wiseman, The State of State Shale Gas

Regulation, Executive Summary, May 2013, pg 5 162 Ibid. 163 Simon Robb, A Best Practice Regulatory Proposal for Shale Gas Production, The University of Western

Australia, 2014, pg 66 164 Crawford School of Public Policy, Unconventional Gas Production and Water Resources, Lessons from the

United States on better governance – a workshop for Australian government officials, 2012, pg 47 at

https://crawford.anu.edu.au/pdf/inthenews/12186-unconventional-gas-document-web-fa.PDF

33

least because it is likely that Australia is poised to become one of the next major shale and tight

gas producing countries.

This thesis will compare Western Australia’s Petroleum and Geothermal Energy Resources

Act 1967 (WA) (PGERA) and South Australia’s Petroleum and Geothermal Act 2000 (SA)

(PGEA) to Colorado’s Oil and Gas Conservation Act (Colo. Rev. Stat. § 34-60-100, et seq.)

(OGCA). It will also examine Western Australia’s Petroleum and Geothermal Energy

Resources (Environment) Regulations 2012 (WA) (PGERA Environment Regulations),

Petroleum and Geothermal Energy Resources (Resources Management and Administration)

Regulations 2015 (WA) (PGERA Administration Regulations) and South Australia’s

Petroleum and Geothermal Energy Regulations 2013 (SA) (PGER) to Colorado’s Oil and Gas

Conservation Commission Rules (COGCC rules).

1.7 Legislative intent

The PGERA and PGEA have a slightly different focus to the OGCA. The PGERA and PGEA

contain no clear and unequivocal statement of legislative intent with regard to the exploitation

of shale and tight gas, which is not surprising given they were both drafted with conventional

gas in mind. The different regulatory approaches and legislative focus is one of the reasons

both the PGERA and PGEA are deficient in certain areas.

The PGERA deals with ‘the exploration for, and the exploitation of, petroleum resources,

geothermal energy resources, and certain other resources, within certain lands of the State...’165

and the PGEA covers the ‘exploration for, and the recovery or commercial utilisation of,

petroleum and certain other resources; and for other purposes.’166 In stark contrast, the

legislative declaration of the OGCA states, amongst other things, that ‘it is declared to be in

the public interest to: Foster the responsible, balanced development, production, and utilization

165 Petroleum and Geothermal Energy Resources Act 1967 (WA), Long title 166 Petroleum and Geothermal Energy Act 2000 (SA), Long title

34

of the natural resources of oil and gas in the state of Colorado in a manner consistent with

protection of public health.’167

The COGCC operates in a similar way to the DMIRS and South Australia’s Department of

Premier and Cabinet (DPC) in that it promotes exploration, development, and conservation of

gas, controls drilling and hydraulic fracturing permit processes and ensures operators comply

with state-wide gas statutes and regulations. However, the PGERA and PGEA do not explicitly

emphasise the role played by DMIRS or DPC respectively. By comparison, the OGCA

explicitly empowers the COGCC to ‘prevent the escape of oil or gas from one stratum into

another, the intrusion of water into oil or gas stratum, the pollution of fresh water supplies by

oil, gas, salt water, or brackish water.’168 The OGCA states that the COGCC regulates ‘oil and

gas operations so as to prevent and mitigate significant adverse environmental impacts on any

air, water, soil, or biological resource resulting from oil and gas operations to the extent

necessary to protect public health, safety, and welfare, including protection of the

environment’.169

The COGCC fosters reliable, balanced development, production, and utilisation of oil and gas

in Colorado.170 The COGCC’s role expanded in the early 1990’s and it began to consider the

environmental impacts and public health, safety and welfare.171 The COGCC administers rules

and regulations and has operational standards and requirements for industry activity.172 The

differences go much further that mere legislative intent. The COGCC ‘provides rules and

regulations to establish operational standards and requirements for industry activity in the

state.’173

In 2007, Colorado’s General Assembly enacted House Bill 1341 which elevated the protection

of the environment as a key role for the COGCC. The legislative declaration at the beginning

167 Oil and Gas Conservation Act (Colorado), § 34-60-102(1)(a)(i) 168 Oil and Gas Conservation Act (Colorado), §34-60-106(c) 169 Oil and Gas Conservation Act (Colorado), §34-60-106, 170 Oil and Gas Conservation Act (Colorado), § 34-60-102(1)(a)(i) 171 Chase v. Colo. Oil & Gas Conservation Comm’n, 2012 COA 94M, 25, 284 P.3d 161, 165-66 (Colo. App.

2012). 172 Colorado Oil & Gas Conservation Commission, at https://cogcc.state.co.us/reg.html#/overview (assessed 23

May 2017) 173 Ibid

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of the OGCA was revised to declare it to be in the public interest to foster ‘responsible,

balanced’ development of oil and gas in a manner not only consistent with the protection of

public health, safety and welfare, but also the protection of the environment.174 The Colorado

Supreme Court recently announced that it would review the Colorado Court of Appeals ruling

in Martinez v. Colorado Oil & Gas Conservation Commission, a challenge to the authority of

the COGCC authority to issue new oil and gas drilling permits.175

In 2013, a number of teenagers, including Martinez, asked the COGCC not to issue new oil

and gas drilling permits unless it could be done in a way that does not ‘ impair Colorado’s

atmosphere, water, wildlife, and land resources, does not adversely impact human health and

does not contribute to climate change’.176 For many years, the COGCC interpreted the OGCA

so as to balance production with other policy objectives.177 Previous court decisions determined

that the OGCA required the COGCC to consider an assortment of policies when making

decisions.178 The court of appeals rejected the COGCC’s long held interpretation and

determined that the COGCC could disregard the OGCA’s directive to foster responsible oil

and gas development and enact rules that would prohibit oil and gas related activity unless they

occurred with zero environmental impact.179

1.8 Thesis structure

Chapter 2 of this thesis provides some context for the comparative regulatory analysis. It is

divided into two sections. The chapter defines unconventional gas, with a particular focus on

shale and tight gas, and examines the production stages and production methods required to

exploit shale and tight gas, the footprint of shale and tight gas operations and resource

classifications. The chapter also summarises Australia’s shale and tight gas prospectivity.

174 Colorado Oil and Gas Conservation Commission , A Decade of Change: COGCC Policy, Regulation,

Transparency - 2007-2017, http://cogcc.state.co.us/documents/about/Summary_COGCC_RM_2007_2018.pdf 175 Martinez v. Colo. Oil and Gas Conservation Comm’n, 2017 COA 37 176 Martinez, Colorado Court of Appeals, Court of Appeals No. 16CA0564, City and County of Denver District

Court No. 14CV32637, pg 3 177 Colorado Oil and Gas Conservation Commission’s Petition for Writ of Certiorari, Case No: 17 SC 297, pg 1 178 Ibid. 179 Ibid.

36

Chapter 2 also summarises the role of water, volume required and availability in Australia in

the context of the exploitation of shale and tight gas. The remainder of Chapter 2 encompasses

a literature review that focuses on the community concerns with shale and tight exploitation

and the key regulatory issues.

Chapter 3 provides a brief history of mineral and petroleum ownership, which includes an

examination of indigenous rights. The chapter also examines regulatory approvals focusing

on environmental approvals and assessment. Chapter 3 also examines the various regulatory

approaches that can be used to manage the exploitation of shale and tight gas.

Chapter 4 comprises a comparative analysis of the regulatory issues. The chapter examines,

amongst other things, access agreements, water trigger and the state based water legislation

of the three jurisdictions. It also examines public disclosure of chemicals and Colorado’s

reclamation regulations.

Chapter 5 summarises the gaps that exist in Western Australia and South Australia concerning

land access, water access and quality protection, regulation of well technology for drilling and

hydraulic fracturing and decommissioning and associated issues. This chapter presents a

number of recommendations that should be implemented by Western Australia and South

Australia to fill the gaps in their regulatory regimes.

1.9 Conclusion

Western Australia, South Australia and Colorado have very diverse regulatory regimes to

manage the exploitation of shale and tight gas. This is not unexpected. While regulatory

diversity is common and not a significant problem, the question of whether it is appropriate

depends largely on whether it is embedded in underlying differences.180 There are particular

aspects of shale and tight gas regulatory regimes that the author believes should not be handled

180 Nathan Richardson, Madeline Gottlieb, Alan Krupnick, and Hannah Wiseman, The State of State Shale Gas

Regulation, Executive Summary, May 2013, pg 5

37

in a different way merely because exploitation is occurring in a different jurisdiction, even if

the jurisdiction is outside Australia.

The way in which jurisdictions regulate the exploration, production and abandonment of shale

and tight gas is clearly more heterogenous than homogenous.181 This is particularly the case

when Western Australia and South Australia’s regulatory regimes are compared to Colorado.

The ‘heterogeneity of shale gas regulations is widespread and it can be seen in what states

regulate and how stringently they do so’.182 The differences in regulation may well reflect the

fundamental differences of geology, hydrology, demographics, or other issues that affect the

local risks to the industry or unplanned variation that has occurred over decades of

regulation.183 Regulators can benefit from prolonged research into the sources of heterogeneity

to ensure that they are making decisions that adequately protect the public and the

environment.184

The author contends that the PGERA and PGEA lack a number of key provisions when they

are compared to the OGCA. The OGCA is succinct and complimented by detailed and easily

digestible COGCC rules. The COGCC rules and regulations establish operational standards

and requirements for industry activity in Colorado.185 There are numerous COGCC rules that

should be considered by Western Australia and South Australia for inclusion in the PGERA

and PGEA respectively.

The remaining chapters of the thesis will examine whether the PGERA and PGEA lack

favourable regulations that address, amongst other things, land access, water use, drilling, well

integrity and rehabilitation. The author contends that the PGERA and PGEA do not adequately

protect underground, surface or drinking water and lack key features which, if included, would

make them effective at regulating shale and tight gas exploitation.

181 Simon Robb, A Best Practice Regulatory Proposal for Shale Gas Production, The University of Western

Australia, 2014, pg 84 182 Nathan Richardson, Madeline Gottlieb, Alan Krupnick, and Hannah Wiseman, The State of State Shale Gas

Regulation, Executive Summary, May 2013, pg 5 183 Ibid 184 Ibid 185 Colorado Oil & Gas Conservation Commission at https://cogcc.state.co.us/reg.html#/overview

38

The result of undertaking a comparative analysis into the regulatory regimes in Western

Australia, South Australia and Colorado will be the identification of a number of provisions

within the OGCA and COGCC rules for managing the issues identified in this introduction.

The thesis has chosen not to consider how the Paris Agreement186 commitments may, or may

not, impact Western Australia and South Australia’s expectations of developing shale and tight

gas. Several years ago, the United Kingdom government approved hydraulic fracturing in

Lancashire and some in the community suggested that the government was making a statement

that the government was not interested in abiding by ‘either the spirit or the maths of the Paris

agreement.’187 The same question may be asked in Australia when governments approve the

development of the shale and tight gas industry but that question is not answered in this

thesis.188

186 United Nations Framework Convention on Climate Change, The Paris Agreement, (2018) at

http://unfccc.int/paris_agreement/items/9485.php 187 Letters, In their clamour for shale gas, ministers forgot the climate agreement, The Guardian, (16 October

2016 at https://www.guardian.com/environment/2016/oct/16/in-their-clamour-for-shale-gas-ministers-forgot-

the-climate-agreement 188 Sangita Bista, Philip Jennings and Martin Anda, ‘Cradle to grave GHG emissions analysis of shale gas

hydraulic fracking in Western Australia’ (2017) 2:45 Renew. Energy Environ. Sustain. 2, 2

39

2 CONTEXT FOR THE COMPARATIVE REVIEW

Some suggest this shale gas boom is a bridge to a more sustainable energy future that

provides abundant and geologically distributed energy with environmental advantages

relative to current alternatives such as coal. Others view the environmental impacts

from shale gas development, on water resources in particular, as being too uncertain

and risky.189

2.1 Introduction

Shale and tight gas exploitation ‘has sparked considerable debate in many parts of the world

and has often been described as a geopolitical game changer.’190 It has emerged as a significant

energy source in the United States and has been described by various industry commentators

as a ‘revolution’191, ‘a paradigm shift’192 , a ‘boom’193 and a ‘golden age.’194 Some have

suggested that Australia is currently in the midst of its own ‘shale gale.’195 Australia’s first

shale gas assessment project was conducted in the Cooper Basin in 2006.196 The first vertical

well targeting shale gas was drilled in the Cooper basin in 2010.197 By December 2012, a

minimum of nine ‘plays’ were being explored by more than 20 joint ventures.198 Initial well

flow rates ranged from 1.000 million cubic feet per day (mmcf/d) to 2.600 mmcf/d.199 These

189 Rahm, B, G and Riha, S, J, ‘Evolving shale gas management: water resource risks, impacts, and lessons

learned’ (2014) 16 Environ. Sci: Processes Impacts 1400, 1409 at

<http://pubs.rsc.org/en/content/articlepdf/2014/EM/C4EM00018H> 190 Jonas Teusch, ‘Shale Gas and the EU Internal Gas Market: Beyond the hype and hysteria’ (EPS Working

Document No. 369, (September 2012) 1-12 191 D Brooks, ‘Shale Gas Revolution’, New York Times, 3 November 2011. Available at:

http://www.nytimes.com/2011/11/04/opinion/brooks-the-shale-gas-revolution.html Viewed 20 January 2015. 192 P Cook, V Beck, D Brereton, R Clark, B Fisher, S Kentish, J Toomey and J Williams, Engineering Energy:

Unconventional Gas Production, Report for the Australian Council of Learned Academies, May 2013, p 35

(referred to in this report as the ACOLA Report). 193 President Barack Obama, The White House, Office of the Press Secretary, Remarks by the President in State

of the Union Address, 12 February 2013. Available at: http://www.whitehouse.gov/the-

pressoffice/2013/02/12/remarks-president-state-union-address 194 International Energy Agency, Golden Rules for a Golden Age of Gas, World Energy Outlook Special Report

on Unconventional Gas, 2011, pg 47 at

http://www.worldenergyoutlook.org/media/weowebsite/2012/goldenrules/WEO2012_GoldenRulesReport.pdf 195 Robertson, S, “Unconventional Gas – Legal Issues’ (2012) AMPLA Yearbook 311 196 DMITRE, “Roadmap for Unconventional Gas Projects in SA” (2012), Ch 4. 197 UCL International Energy Policy Institute Adelaide, Australia, Shale Gas in Australia: The Policy Options,

Green Paper, October 2013 at https://www.ucl.ac.uk/australia/files/shale-gas-in-australia-green-paper-final 198 Inquiry into Unconventional Gas (Fracking) Interim report, Parliament of SA, (2015), pg 14 199 Ibid.

40

rates are similar to those in the United States.200 The government of South Australia estimates

that the Cooper Basin will reach 2500 shale wells in total by 2028, recovering some 6.0 trillion

cubic feet (tcf) of gas.201 The state’s first commercial shale gas development was initiated by

Santos with the Moomba-191 vertical shale well.202 The BG Group obtained shale interests

from Drillsearch in 2011 and in 2013, Chevron agreed to fund exploration operations to gain a

stake in petroleum titles from Beach Energy.203 Beach Energy, Drillsearch Energy, Senex

Energy, Strike Energy and Icon Energy are currently assessing shale potential in the Cooper

Basin.204

In Western Australia, there is significant activity in the Canning Basin, led by Buru and New

Standard Energy.205 Buru entered into a ‘farm-out’ agreement with Mitsubishi in June 2010.206

In November 2013, Apache Energy joined the Buru/Mitsubishi joint venture.207 In June 2014,

the DMIRS approved Buru’s Laurel Formation Tight Gas Pilot Exploration programme, which

set out to identify the potential environmental impacts and risks associated with exploration.208

The programme involved stimulating tight gas zones in existing vertical exploration wells to

assess marketable potential.209 Since 2005, 17 exploration wells have been drilled in Western

Australia looking for shale and tight gas.210 Seven of these were fractured, with six in the

Perth Basin and one in the Canning Basin.211 The most recent well to undergo fracking was in

August 2015 (figure as at July 2015).212

200 Lippman Consulting Inc, Lower 48 states shale initial production report, 2011 201 Department for Manufacturing, Innovation, Trade, Resources and Energy, SA Roadmap for unconventional

gas projects in SA, Government of SA: Energy Resources Division, Department for Manufacturing,

Innovation, Trade, Resources and Energy, 2012 at

<http://petroleum.statedevelopment.sa.gov.au/__data/assets/pdf_file/0019/238033/Roadmap_Unconventional_

Gas_Projects_SA_12-12-12_web.pdf> 202 UCL International Energy Policy Institute Adelaide, Australia, Shale Gas in Australia: The Policy Options,

Green Paper, October 2013 at https://www.ucl.ac.uk/australia/files/shale-gas-in-australia-green-paper-final 203 Liz Allnutt, Australia: Shale gas handbook for Australia, Norton Rose Fulbright Australia, 2015 at

http://www.mondaq.com/australia/x/409972/Oil+Gas+Electricity/Shale+gas+handbook+for+Australia 204 Ibid. 205 Ibid. 206 Buru Energy at http://www.buruenergy.com/company-overview-buru-energy/our-history/ (accessed 21 June

2017) 207 Ibid. 208 Ibid. 209 Ibid. 210 Department of Mines, Industry Regulation and Safety, Shale and tight gas exploration in Western Australia

at http://www.dmp.wa.gov,au/Petroulem /Shale-and-tight-gas-exploration-19990.aspx , (accessed 13 May

2017) 211 Ibid. 212 Ibid.

41

This chapter broadly outlines the key characteristics of unconventional gas and then provides

a definition of shale gas and tight gas. The chapter examines the methods used to exploit shale

and tight gas, namely, horizontal drilling and hydraulic fracturing and provides the reader with

an understanding of the surface footprint of shale and tight gas operations in terms of well

numbers, surrounding land, infrastructure and ground and surface water impacts. The chapter

examines Australia and Colorado’s reserves and basins, sets out the resource classification

types and examines Western Australia and South Australia’s shale and tight gas prospectivity.

It also considers the role water plays in developing shale and tight gas and surveys the likely

impact in, and around the Great Artesian Basin and Canning Superbasin. The chapter also

includes a literature review that sets out a number of community concerns and regulatory

issues.

2.2 Shale gas, tight gas and water

It is important to note that the gas in conventional basins has the same composition as the gas

in unconventional basins.213 Unconventional gas is a fossil fuel that contains up to 90 percent

methane with the balance consisting of ethane, propane, butane, carbon dioxide, oxygen,

nitrogen, hydrogen sulphide and trace amounts of other gases.214 It is porous and its low-

permeability features act like a sponge.215 It is the complicated production methods that are

required to extract shale and tight that also differentiate conventional gas from unconventional

gas.216

Unconventional gas is sourced from geological formations.’217 These consist of rock strata

that have a similar lithology, facies or other similar properties.218 Geological formations play a

213 CSIRO, What is conventional and unconventional gas? (25 February 2015) at

https://www.csiro.au/en/Research/Energy/Hydraulic-fracturing/What-is-unconventional-gas ; AWE, What is

conventional and unconventional gas? at http://www.awemidwest.com.au/how-we-produce-gas/shale-tight-

coal-seam-gas/ (accessed 29 June 2017) 214 Natural Gas, AMMA, Resource Industry Employer Group (accessed 15 May 2016), at

http://www.miningoilgasjobs.com.au/oil-gas-energy/hydrocarbons-and-energy/hydrocarbons/oil-and-

gas/downstream/natural-gas.aspx, 215 Burwen, J & Flegel, J, Unconventional Gas Exploration & Production, Case studies on the Government’s

role in Energy Technology Innovation, March 2013, page 1-3 at http://americanenergyinnovation.org/wp-

content/uploads/2013/03/Case-Unconventional-Gas.pdf 216 Shale Gas Information Platform, Basics of Shale Gas, (accessed 18 May 2017) at http://www.shale-gas-

information-platform.org/areas/basics-of-shale-gas.html 217 Department of Industry, Innovation and Science, Unconventional gas, what is it? (accessed 18 May 2016) at

https://industry.gov.au/resource?Upstream 218 Utah Geological Survey, What is a Formation? (accessed 23 May 2017) at https://geology.utah.gov

42

role in the exploration and production of petroleum and they have significant consequences for

licensing regimes.219 Shale and tight gas exploitation often requires operators to drill large

numbers of wells in large production areas, areas that are usually much larger than for

conventional reservoirs.220

The complex geological systems that contain unconventional gas make it quite hard to exploit,

requiring relatively new technological solutions, namely, horizontal drilling and hydraulic

fracturing.221 The composition of the rock containing the gas prevents it from migrating and

results in an absence of reservoirs or collective pools.222 A pool is ‘an underground reservoir

containing a common accumulation of oil or gas, or both’.223 According to the United States

Department of Energy, ‘in a conventional reservoir, the gas is interconnected pore spaces,

much like a kitchen sponge, that allow easier flow to a well; but in an unconventional reservoir,

like shale, the reservoir must be mechanically “stimulated” to create additional permeability

and free the gas for collection.’224

219 John Chandler, ‘Shale gas and government agreements in WA’ (2014) 33 ARELJ 44, 46 220 John Chandler, ‘Shale gas and government agreements in WA’ (2014) 33 ARELJ 44, 46 221 CSIRO, What is unconventional gas? at http://www.csiro.au/en/Research/Energy/Hydraulic-fracturing/What-

is-unconventional-gas 222 John Chandler, ‘Shale gas and government agreements in WA’ (2014) 33 ARELJ 223 OGCA, definitions, (9) ‘Pool’ 224 Natural Gas From Shale: Questions and Answers, How is Shale Gas Produced at <

https://www.energy.gov/sites/prod/files/2013/04/f0/how_is_shale_gas_produced.pdf>

43

The various permeability types can be seen in the following diagram:

Figure 1 Low porosity- impermeable rock to high porosity-permeable rock225

Shale gas is trapped in shale formations226 characterised by low permeable sedimentary rock227

at depths between 2000 and 5000 metres.228 This type of gas is more difficult to produce than

coal seam gas given shale is much harder, more impermeable and typically found deep

underground.229 Shales are usually found in source rock where there has been no migration of

225 Department of Mines, Industry Regulation and Safety, Guide to the Regulatory Framework for Shale and

Tight Gas in Western Australia, A Whole of Government Approach, 2015 Edition at

http://www.DMIRS.wa.gov.au/Documents/Petroleum/WEB_Shale_and_Tight_Gas_Framework.pdf 226 United States Energy Information Administration, Geoscience News & Information, Energy in Brief (2010),

What is Shale Gas? at http://geology.com/energy/shale-gas/ 227 Catriona, Dr R, ‘Unconventional Gas: Coal Seam Gas, Shale Gas and Tight Gas, An introduction and

overview of issues relevant to the development of unconventional gas in Victoria’, Parliament of Victoria,

(December 2013) 228 Department of Mines, Industry Regulation and Safety, Natural Gas from Shale and Tight Rocks, ‘An

overview of Western Australia’s regulatory framework’, February 2014 at

http://www.DMIRS.wa.gov.au/documents/Natural_Gas_from_Shale_and_Tight_Rocks_-

_An_overview_of_Western_Australia_regulatory_framework.pdf 229 J. Rutovitz, S. Harris, N. Kuruppu and C. Dunstan Drilling Down. Coal Seam Gas: A Background Paper,

November, prepared by Institute for Sustainable Futures UTS for the City of Sydney Council, 2011 pg 3

44

petroleum resulting in the absence of a reservoir or pool.230 Shales are so impermeable that

hydraulic fracturing is essential to enable the gas to flow.231 Large amounts of water are required

to exploit shale gas compared to coal seam gas.

Shale gas exploitation does not produce the large amounts of water compared to the coal seam

gas dewatering process.232 Tight gas is found in rock (often sandstone but also carbonate)233

with very low permeability at depths of between 2000 and 5000 metres.234 The holes between

the rocks containing tight gas are very small and the interconnections between them so narrow

that the gas migrates with great difficulty.235 Large amounts of water are needed to extract tight

gas via hydraulic fracturing.

230 Ibid 231 Ibid 232 Cook, P, Beck, V, Brereton, D, Clark, R, Fisher, B, Kentish, S, Toomey, J and Williams, J (2013). Securing

Australia’s Future – Engineering energy: unconventional gas production,pg 29 at

http://www.acola.org.au/index.php/projects/securing-australia-s-future/project-6 233 Department of Mines, Industry Regulation and Safety, Guide to the Regulatory Framework for Shale and

Tight Gas in Western Australia, A Whole of Government Approach, 2015 Edition, pg 6 at

http://www.parliament.wa.gov.au/publications/tabledpapers.nsf/displaypaper/3913541ae03e783bf52cf5b94825

7ee5000a9d20/$file/3541.pdf 234 Department of Mines, Industry Regulation and Safety, Shale and Tight Gas in Western Australia: An

overview of Western Australia’s regulatory framework, August 2016 at <

http://www.dmp.wa.gov.au/Documents/Petroleum/Shale_and_Tight_Gas_overview.pdf> 235 Catriona, Dr R, ‘Unconventional Gas: Coal Seam Gas, Shale Gas and Tight Gas, An introduction and

overview of issues relevant to the development of unconventional gas in Victoria’, Parliament of Victoria,

(December 2013)

45

The following diagram shows the geology of natural gas reserves:

Figure 2 Schematic geology of natural gas resources236

The far right vertical well is producing gas from a conventional oil and gas deposit. The grey

layer (the confining layer) traps oil (green) or gas (red). The well second from the right is

producing gas from unconventional formations: a vertical coal bed methane well. A horizontal

well (centre) is producing from a shale formation and a well is producing from a tight sand

formation (left). The difference between conventional gas and unconventional gas is not

chemical composition (given it is all natural gas), but rather the result of the geological

characteristics and location.237

236 Intermountain Oil and Gas BMP Project, the Colorado Rural Water Association, AirWaterGas and Western

Resource Advocates, Protecting source water in Colorado during oil and gas development, August 2016, pg 1 at

http://www.oilandgasbmps.org/docs/CO186_ProtectingSourceWaterAugust2016.pdf 237 Total, Three main sources of unconventional gas, (accessed 12 May 2016) at

http://www.total.com/en/energies-expertise/oil-gas/exploration-production/strategic-sectors/unconventional-

gas/presentation/three-main-sources-unconventional-gas

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2.2.1 Production stages and production methods: Drilling and fracturing

Operators typically ‘exercise the right to control the conduct of oil and gas operations.’238

They undertake exploration, production and abandonment activities.239 During exploration

they carry out drilling, seismic surveys, sample shale rock and flow testing.240 They also

assemble well pads, install drilling rigs and normally transport equipment, water and chemicals

to and from well sites. During production operators are likely to increase their drilling activities

and commence hydraulic fracturing.241 They may also remove water from sites for treatment

and disposal. During the production phase operators typically carry out maintenance activities

and drill additional wells (this level of activity is likely to decline over time). The final stage

of exploitation involves restoring sites to their original condition. Operators must ensure wells

are safe for abandonment and remove wells pads and drilling rigs. Well decommissioning and

restoration activities can occur at any time if operators choose not to move from exploration to

production.242

Horizontal drilling (also known as directional drilling or deviated drilling) involves operators

transferring a wells path from vertical to horizontal.243 Horizontal drilling has been described

as a process where a ‘wellbore is drilled vertically to a kick-off depth above the target formation

and then angled through a wide ninety degree arc so that the producing portion of the well

extends horizontally through the target formation’.244

238 COGCC rules and regulations, definitions (100 series) 239 Frogtech Pty Ltd, Potential Geological Risks Associated with Shale Gas Production in Australia, Melbourne:

Australian Council of Learned Academics, 2013 pg 2 at

http://www.acola.org.au/PDF/SAF06FINAL/Frogtech_Shale_Gas_Geology_and_Risks%20Jan2013.pdf 240 Stephenson Halliday, Environmental Planning, Landscape Architecture, Planning Advisory Service,

Planning for Shale Gas and Oil – Briefing note March 2016, pg 6 at

https://www.local.gov.uk/sites/default/files/documents/shale-gas-and-oil-explora-471.pdf 241 Ibid. 242 Ibid. 243 The Australian Petroleum Production and Exploration Association, Horizontal drilling, (accessed 12 August

2016) at http://www.appea.com.au/oil-gas-explained/operation/horizontal-drilling/ 244 Canadian Society of Unconventional Resources, ‘Understanding Water and Unconventional Resources’

(Information Booklet) 22, (accessed 14 July 2017) at

http://www.csur.com/sites/default/files/Undertsnding_Water_final_pdf

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The use of horizontal drilling has reduced surface impacts and improved production.245 This

is the result of greater contact with the productive strata of reservoirs.246 The technological

advances that have occurred have enabled operators to drill gas formations and redirect drills

through gas-bearing areas enabling up to six wells to be operated from one surface drilling

pad.247

The following diagram shows vertical and horizontal drilling:

Figure 3 Vertical vs Horizontal drilling248

245 The Australian Petroleum Productions and Exploration Association, Horizontal drilling, (accessed 15 June

2017) at http://www.appea.com.au/oil-gas-explained/operation/horizontal-drilling/ 246 Burwen, J & Flegel, J, Unconventional Gas Exploration & Production, Case studies on the Government’s

role in Energy Technology Innovation, March 2013, page 1-3 at http://americanenergyinnovation.org/wp-

content/uploads/2013/03/Case-Unconventional-Gas.pdf 247 Shale gas in Australia, Hydraulic fracturing, (accessed 21 May 2017) at http://www.shale-

gas.com.au/industry-operations/hydraulic-fracturing/ 248 Keystone Exploration, Vertical vs Horizontal drilling, (accessed 13 June 2017) at http://www.kx-

kp.com/?page=drilling&type=natural_gas

48

Hydraulic fracturing is a process of well stimulation post drilling.249 The process involves

injecting fluid at high pressure into wells and target rock to produce fractures a few millimetres

wide that extend hundreds of metres.250 This enables fluid to fill the fractures to keep them

from resealing allowing the gas to flow into the well for extraction.251 Hydraulic fracturing has

increased the productivity of shale and tight gas wells.252 Wells are fractured continually over

the course of an operation as fractures reseal naturally over time.253 Typically wells have a

valuable production life of 20 – 40 years, and should be re-fractured every three to five years

so they continue to have an economically viable production flow.254

Hydraulic fracturing fluid comprises water, sand and chemicals. The volume of water, which

is almost 100 percent of the fluid, varies from project to project and on the size and length of

the well, and the type of rocks being fractured.255

249 American Society of Civil Engineers, Policy Statement 539 – Hydraulic Fracturing, 20 July 2012 at

http://www.asce.org/Public-Policies-and-Priorities/Public-Policy-Statements/Policy-Statement-539---

Hydraulic Fracturing/ 250 Jackson RB, Rainey Pearson B, Osborn SG, Warner NR and Vengosh A, Research and Policy

Recommendations for Hydraulic Fracturing and Shale-Gas Extraction (Centre on Global Change, Duke

University, Durham NC, 2011). 251 Burwen, J & Flegel, J, Unconventional Gas Exploration & Production, Case studies on the Government’s

role in Energy Technology Innovation, March 2013, page 1-3 at http://americanenergyinnovation.org/wp-

content/uploads/2013/03/Case-Unconventional-Gas.pdf 252 Australian Petroleum Production & Exploration Association ‘Hydraulic Fracturing’, 2013, APPEA website,

viewed 12 September 2013. 253 Burwen, J & Flegel, J, Unconventional Gas Exploration & Production, Case studies on the Government’s

role in Energy Technology Innovation, March 2013, page 1-3 at http://americanenergyinnovation.org/wp-

content/uploads/2013/03/Case-Unconventional-Gas.pdf 254 Hoffman, A., Olsson, G., Lindstrom, A. 2014. Shale and Hydraulic Fracturing: Framing the Water Issue.

Report Nr 34. SIWI, Stockholm, pg 18 255 Department of Mines, Industry Regulation and Safety, Natural Gas from Shale and Tight Rocks, An

overview of Western Australia’s regulatory framework, (accessed 15 June 2017) at

http://www.DMIRS.wa.gov.au/documents/Natural_Gas_from_Shale_and_Tight_Rocks_-

_An_overview_of_Western_Australia_regulatory_framework.pdf

49

The below diagram shows a horizontal well and hydraulic fracturing:

Figure 4 Horizontal well and Hydraulic Fracturing256

2.2.2 Footprint – shale gas, tight gas and water

The footprint of a shale and tight gas operation can be, but is not exclusively, defined by the

number of wells and surrounding land and infrastructure operators require for exploration,

production and abandonment and by the environmental impacts, for example, the impact on

ground and surface water.257 The priority for operators should be, and often is, the

minimisation of the impacts on, amongst other things, the land it uses and the water resources

it exploits to reduce its gas footprint.258 Ideally, operators should continually endeavour to

minimise the impacts on ground and surface water to reduce their shale gas footprint.259 Some

256 ECCO Foxvalley, Horizontal well and hydraulic fracturing, (accessed 17 June 2016) at http://ecco-

foxvalley.net/blog/2013/01/15/fracking-what-is-it/ 257 Hydraulic Fracturing, Shale gas in Australia (accessed 12 May 2018) at < https://www.shale-

gas.com.au/industry-operations/hydraulic-fracturing/> v 258 Shale gas in Australia, Hydraulic fracturing, (accessed 18 June 2017) at http://www.shale-

gas.com.au/industry-operations/hydraulic-fracturing/ 259 Ibid.

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argue that the land-use footprint of shale and tight gas operations is not considerably more than

for conventional operations.260 Though given more wells are required to produce

unconventional gas than are required to produce conventional gas, there are likely to be much

larger production areas.261 The DMIRS estimate that a well pad requires roughly 1.5 to 2

hectares of cleared land and an established gas field may contain a single well pad per 225

hectares.262 After initial drilling has been completed the majority of land that operators use is

rehabilitated, leaving only a small cleared area around each well head.263 The Chamber of

Minerals and Energy Western Australia suggest that a ‘drilling rig, plus associated equipment

and pits or vessels to store drilling fluids and waste will typically occupy and area of

approximately 150 x 150 metres.’264

Shale and tight gas plays need a high concentration of wells and multistage hydraulic fracturing

to ensure commercially viability, which leads to the use of high concentration of well pads to

cut land costs, environmental impact and productivity through batch drilling.265 The footprint

of shale and tight gas operations is significantly reduced by the use of multi-well pads

(MWP’s).266 MWP’s also reduce production costs.267 The size of a pad is affected by the

amount of space required to accommodate equipment for horizontal drilling, hydraulic

fracturing and for water storage.268 A standard well site in the US averages between 1.5 and

260 Natural Resources Canada, Environmental Considerations of Shale and Tight Resource Development,

(accessed 12 May 2017) at https://www.nrcan.gc.ca/energy/sources/shale-tight-resources/17682> 261 John Chandler, ‘Shale gas and government agreements in WA’ (2014) 33 ARELJ 262 Department of Mines, Industry Regulation and Safety, Natural Gas from Shale and Tight Rocks, An

overview of Western Australia’s regulatory framework, February 2014, pg 6 at

http://www.DMIRS.wa.gov.au/documents/Natural_Gas_from_Shale_and_Tight_Rocks_-

_An_overview_of_Western_Australia_regulatory_framework.pdf 263Shale Gas in Australia, Hydraulic fracturing,(12 March 2017) at http://www.shale-gas.com.au/industry-

operations/hydraulic-fracturing/ 264 Parliamentary Inquiry into the Implications for Western Australia fir Unconventional Gas, Submission for

the Chamber of Minerals and Energy Western Australia, September 2013, pg 19 at <

http://www.parliament.wa.gov.au/Parliament/commit.nsf/(Evidence+Lookup+by+Com+ID)/99D8D0023E339

C6F48257C4000110456/$file/ev.fra.131004.sub.112.the+chamber+of+minerals+and+energy+of+western+aus

tralia.pdf> 265 Ogoke, Victor, Bouchard, Genevieve, Inglehart, S.C., Simultaneous Operations in Multi-Well Pad: a Cost

Effective way of Drilling Multi Wells Pad and Deliver 8 Fracs a Day, 2014, Society of Petroleum Engineers,

2014, SPE Annual Technical Conference and Exhibition, 27-29 October, Amsterdam, The Netherlands at

https://www.onepetro.org/conference-paper/SPE-170744-MS 266 Legislative Council of Western Australia, Standing Committee on Environment and Public Affairs, Report

42, Implications for Western Australia of Hydraulic Fracturing for Unconventional Gas, November 2015, pg

26 at

http://www.parliament.wa.gov.au/Parliament/commit.nsf/(Report+Lookup+by+Com+ID)/74E61E739E39E57

748257EF9002150FE/$file/ev.fra.151117.rpf.042.xx.pdf 267 Id at 25. 268 Id at 26.

51

2.0 hectares during drilling, though pads of over 2.0 hectares are possible.269 The technological

advances that have occurred in gas production over several decades has allowed operators to

drill gas formations and redirect drills through gas-bearing areas enabling up to six wells to be

operated from one surface drilling pad.270 A number of horizontal wells can be drilled in

multiple directions from a single well pad.271 Generally, four wells are contained on a single

pad, though pads have supported up to eight wells resulting in a smaller surface footprint, as

less pads and roads are required to produce the same amount of gas as single well pads.272

The groundwater footprint of operations is the area required to sustain groundwater use and

groundwater-dependent ecosystems.273 The estimated groundwater footprint (to obtain water

for fracking) in the Cooper Basin is 139 times the gas footprint.274 An operator’s footprint can

be reduced by their investment in technology to lower the amount of water they use, however

there are still concerns in relation to consumption levels, the management of competing water

interests and the contamination of groundwater supplies.275 Operators should be mindful of a

locations groundwater sustainable yield which is defined as ‘the groundwater extraction

regime, measured over a specified planning timeframe that allows acceptable levels of stress

and protects dependent economic, social, and environmental values.’276

Shale gas and tight gas operations result in a network of geographically dispersed ‘production

facilities and flow lines.’277 The use of horizontal drilling and hydraulic fracturing has reduced

269 Engineering Energy: Unconventional Gas Production, A study of shale gas is Australia, (Project 6, May

2013), pg 103 at <

https://acola.org.au/wp/PDF/SAF06FINAL/Final%20Report%20Engineering%20Energy%20June%202013.pd

f 270 Shale Gas in Australia, Hydraulic fracturing, (accessed 12 April 2017) at http://www.shale-

gas.com.au/industry-operations/hydraulic-fracturing/ 271 Department of Mines, Industry Regulation and Safety, Guide to the Regulatory Framework for Shale and

Tight Gas in Western Australia, A Whole of Government Approach, 2015 Edition, pg 6 at

http://www.parliament.wa.gov.au/publications/tabledpapers.nsf/displaypaper/3913541ae03e783bf52cf5b94825

7ee5000a9d20/$file/3541.pdf 272 Ibid 273 Tom Gleeson, Yoshihide Wada, Marc F.P Bierkens & Ludovicus P.H van Beek, ‘Water balance of global

aquifers revealed by groundwater footprint’ (2012) 488 Nature 197 274 Ibid. 275 Shale Gas, European Commission, Shale Gas, (accessed 12 September 2017) at

https://ec.europa.eu/energy/en/topics/oil-gas-and-coal/shale-gas 276 Department of Environment and Energy, Definition and approach to sustainable groundwater yield,

(accessed 18 October 2016) at

http://www.environment.gov.au/water/publications/environmental/groundwater/definition-and-approach-

sustainable-groundwater-yield 277 Guarnone M, Rossi F, Negri E, Grassi C, Genazzi D, and Zennaro R, “An Unconventional Mindset for Shale

Gas Surface Facilities” (2012) 6 Journal of National Gas Science and Engineering 14

52

the overall surface footprint of operations allowing multiple wells (typically four wells are

contained on a single pad though some have supported eight wells)278 to be drilled from a single

well pad.279 In 2011, around 30 per cent of newly developed shale and tight gas wells in the

United States and Canada were multiple wells drilled from a single pad.280 Technological

advances now allow for 12 -16 wells to be drilled from a single well pad.281

Shale and tight gas reserves cover large areas in geological formations.282 These formations

play a significant part in the exploration and production of shale and tight gas and have an

impact on licensing regimes.283 For example, in Western Australia a production licence is

limited to, and corresponds with the ‘size of discovery’.284 An exploration permit is limited

to 400 blocks (32,000 square kilometres).285 These limitations suit conventional reservoirs

where licences are around 320 square kilometres.286 In South Australia an exploration licence

cannot be more than 10,000 square kilometres.287 A production licence cannot exceed twice

the area under which the discovery is more likely than not to exceed,288 or 100 square

kilometres.289

The question of whether shale and tight gas operations are best identified as a set of operations

undertaken within the boundaries of a single tenement or single well or classified by their

geological formation over a sequence or series of tenements is not examined in this thesis. It

is worth noting that in Colorado, geographic area plans take account of the activities of a

278 Department of Mines, Industry Regulation and Safety, Guide to the Regulatory Framework for Shale and

Tight Gas in Western Australia, A Whole of Government Approach, 2015 Edition, pg 11 at

http://www.DMIRS.wa.gov.au/Documents/Petroleum/WEB_Shale_and_Tight_Gas_Framework.pdf 279 Department of Mines, Industry Regulation and Safety, Natural Gas from Shale and Tight Rocks, An

overview of Western Australia’s regulatory framework, February 2014, page 6 at

http://www.DMIRS.wa.gov.au/documents/Natural_Gas_from_Shale_and_Tight_Rocks_-

_An_overview_of_Western_Australia_regulatory_framework.pdf 280 International Energy Agency, Golden Rules for a Golden Age of Gas, World Energy Outlook Special Report

on Unconventional Gas, 2011, pg 47 at

http://www.worldenergyoutlook.org/media/weowebsite/2012/goldenrules/WEO2012_GoldenRulesReport.pdf 281 Brian K. Bohm, P.G, J. Daniel Arthur, P.E, Horizontal drilling and hydraulic fracturing considerations for

shale gas wells, ALL Consulting, 13-14October 2010 282 Utah Geological Survey, What is a Formation? (accessed 19 June 2017) at https://geology.utah.gov 283 John Chandler, ‘Shale gas and government agreements in WA’ (2014) 33 ARELJ 284 Id at 48. 285 Petroleum and Geothermal Energy Resources Act 1967, s 31(1) 286 John Chandler, How Are Onshore Licensing Regimes in Australia dealing with the challenges of Petroleum

in Shale and other Tight Rocks? Australian Resources and Energy Law Journal, Vol. 34, No. 3, 2015, p. 251-

266 287 Petroleum and Geothermal Energy Act 2000, s 24(2) 288 Petroleum and Geothermal Energy Act 2000, s 37(1)(a) 289 Petroleum and Geothermal Energy Act 2000, s 37(1)(b)

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number of operators in entire gas fields or basins to enable the implementation of basin specific

rules that promote the purposes of the OGCA.290

2.2.3 Resource classifications and prospectivity

The four main resource classification types are production, reserves, contingent resources and

prospective resources.291 The production classification refers to the amount of gas recovered

at a given date, the reserves classification to the part of resource that is commercially

recoverable and confirmed for development, the contingent resources classification is less

reliable and is potentially recoverable but not ready for commercial development and

prospective resources.292 Prospective resources are undiscovered accumulations293 and

considered ‘potentially recoverable’ on the basis of secondary evidence as these deposits are

yet to be drilled.294 For prospective resources to become contingent resources the barriers that

block commercial development must be removed.295 Contingent and prospective resources are

less certain than production and reserves given there are often commercial and/or technical

barriers that need to be addressed before operators have confidence in production volumes.296

Technically recoverable resources are ‘the volumes of oil and natural gas that could be

produced with current technology, regardless of oil and natural gas prices and production

costs.’297 Economically recoverable resources are those that could be commercially produced

under market conditions. The amount of gas in a formation prior to production is the

‘original gas in-place.’298

290 COGCC Rule 513 291 Kane Rawsthorn, Shale Gas Prospectivity Potential, AWT International, Prepared for: Australian Council of

Learned Academies, 23 January 2013 at

https://acola.org.au/wp/PDF/SAF06Consultants/AWTShale%20Gas%20Prospectivity%20Potential%20Jan201

3.pdf 292 Ibid. 293 SPE International, SPE Petroleum Resources Management System Guide for Non-Technical Users (accessed

24 June 2017), page 3 at http://www.spe.org/industry/docs/PRMS_guide_non_tech.pdf 294 Ibid. 295 Ibid. 296 Above, note 280. 297 United States Energy Information Administration, Technically Recoverable Shale Oil and Shale Gas

Resources: China, September 2015, pg 3 at

https://www.eia.gov/analysis/studies/worldshalegas/pdf/China_2013.pdf 298 I.O. Obielum, P.U. Giegbefumwen, P.O. Ogbeide, A P/Z Plot for Estimating Original Gas in Place in a Geo-

pressured Gas Reservoir by the Use of a Modified Material Balance Equation, SPE Nigeria Annual

54

Operators try to locate prospective areas and align their wells for maximum borehole

exposure.299 Shale gas is located in ‘plays’, which are shale formations that contain deposits

with similar geologic and geographic properties.300 A play that meets certain benchmarks is

classified as a shale gas ‘sweet spot’.301

2.2.4 Reserves and basins

According to the United States Energy Information Administration there are approximately

7299 trillion cubic feet (tcf) of technically recoverable shale gas resources distributed amongst

137 formations in 41 countries.302 The focus on conventional gas exploitation in the United

States has resulted in a significant decline in reserves.303 In fact, conventional gas production

dropped 39 percent between 1990 and 2009.304

The United States reportedly holds 610 tcf of technically recoverable shale natural gas

resources and ranks fourth in the world for shale gas resources.305 To put this into some

context, the Canning Basin alone reportedly contains 235 tcf306 of technically recoverable shale

natural gas. This is roughly double the amount of gas held in Western Australia’s offshore

International Conference, Society of Petroleum Engineers, 2015 < https://www.onepetro.org/conference-

paper/SPE-178354-MS> 299 Kane Rawsthorn, Shale Gas Prospectivity Potential, AWT International, Prepared for: Australian Council of

Learned Academies, 23 January 2013 at

https://acola.org.au/wp/PDF/SAF06Consultants/AWTShale%20Gas%20Prospectivity%20Potential%20Jan201

3.pdf 300 Energy Information Administration, What is a Shale “Play”?, (accessed 17 May 2017) at

http://geology.com/energy/shale-gas/ 301 Above, note 287. 302 US Energy Information Administration, Analysis & Projections-Technically Recoverable Shale Oil and

Shale Gas Resources: An Assessment of 137 Shale Formations in 41 Countries Outside the United States, 13

June 2013, at < http://www.eia.gov/analysis/studies/worldshalegas/> 303 Alberta Energy Regulator, What is Unconventional Oil and Gas? , (accessed 15 June 2017) at

https://www.aer.ca/about-aer/spotlight-on/unconventional-regulatory-framework/what-is-unconventional-oil-

and-gas 304 Crawford School of Public Policy, Unconventional Gas Production and Water Resources, Lessons from the

United States on better governance – a workshop for Australian government officials, 2012, pg 6 at

https://crawford.anu.edu.au/pdf/inthenews/12186-unconventional-gas-document-web-fa.PDF 305 US Energy Information Administration, Shale in the United States, 2016 at

https://www.eia.gov/energy_in_brief/article/shale_in_the_united_states.cfm 306 US Energy Information Administration, World Shale Resource Assessments, 2015 at

http://www.eia.gov/analysis/studies/worldshalegas/

55

conventional fields.307 It is estimated that 1 tcf of natural gas would satisfy Australia’s yearly

domestic gas usage308 or a city the size of Perth for 10 years.309 According to the Australian

Energy Market Operator, supplying gas to the domestic market in Western Australia is

dependent on sustained development of gas reserves, though reserves associated with domestic

gas production exhibit a natural decline.310 This is of particular significance to Western

Australia which consumes more gas domestically than any other state in Australia.311

Shale gas accounted for 2 per cent of United States domestic gas resources in the 2001 and 47

per cent in 2013.312 Approximately 12.3 tcf of dry natural gas was produced directly from

shale and tight oil resources in the United States in 2014.313 Production in this area grew by

an average of 48 per cent from 2006 to 2010.314 It is projected that shale gas will account for

almost half of total natural gas production in 2035.315 Shale gas and tight oil is projected to

grow from roughly 14 tcf in 2015 to 29 tcf in 2040.316

Shale and tight gas delivers the United States over 2 tcf annually to the domestic market and it

is anticipated that it will overtake coal seam gas production by 2025 with enhancements in

exploration, production, gas price increases and developing plays.317 Australia’s shale and

tight gas reserves are difficult to accurately verify given many of its basins are largely

unexplored and underexplored.318 Geoscience Australia maintain that ‘Australia has

307 CSIRO, Australia’s shale gas potential, (accessed 17 June 2017) at

http://www.csiro.au/Outcomes/Energy/Energy-from-oil-and-gas/Shale-gas-potential.aspx 308 CSIRO, Australia’s shale gas resources, (accessed 17 June 2017) at

http://www.csiro.au/Outcomes/Energy/Energy-from-oil-and-gas/Shale-gas-potential.aspx 309 APPEA, Report to the CoAG Energy Council Unconventional Gas in Australia, July 2016, pg 41 at

http://www.appea.com.au/wp-content/uploads/2016/08/APPEA-Report-to-CoAG-2016-Unconventional-Gas-

in-Australia.pdf 310 Australian Energy Market Operator, Gas statement of Opportunities for Western Australia, December 2017,

2018, pg 23 311 AEMO, Gas Statement of Opportunities for Western Australia, 2017 at https://www.aemo.com.au/Media-

Centre/2017-WA-Gas-Statement-of-Opportunities 312US Energy Information Administration, Annual Energy Outlook 2015 at <http://www.eia.gov/forecasts/aeo> 313 United States Energy Information Administration, How much shale gas is produced in the United States?,

(accessed 17 June 2017) at http://www.eia.gov/tools/faqs/faq.cfm?id=907&t=8 314 US Energy Information Administration, Annual Energy Outlook 2011: With Projections to 2035, 4, 2011. 315 Crawford School of Public Policy, Unconventional Gas Production and Water Resources, Lessons from the

United States on better governance – a workshop for Australian government officials, 2012, pg 6 at

https://crawford.anu.edu.au/pdf/inthenews/12186-unconventional-gas-document-web-fa.PDF 316 Above, note 301. 317 Department of State Development, Resource Plays, Shale gas, (16 April 2017) at

http://petroleum.statedevelopment.sa.gov.au/prospectivity/resource_plays#gas 318 Kane Rawsthorn, Shale Gas Prospectivity Potential, AWT International, Prepared for: Australian Council of

Learned Academies, 23 January 2013, pg 12 at

56

significant shale gas resources, but such resources are poorly understood and quantified, and

any estimates of potential resources have a high degree of uncertainty…Understanding of the

potential tight gas and shale gas resource in Australia is limited.’319

Australia’s shale and tight gas reserves are twice the size of those estimated for coal seam

gas.320 It is difficult to do more that estimate the size and extent of reserves given that the final

volumes cannot be identified pre-production.321 Resource estimates fluctuate as new extraction

technologies emerge, as markets develop, and once operators begin to produce.322

The United States Energy Information Administration assessed shale formations in 41

countries outside of the United States in 2013.323 In Australia, the Canning, Cooper,

Maryborough, Perth, Georgina, and Beetaloo basins were ranked according to composite play

success and prospective area success. These basins reportedly hold 2,046 tcf of risked shale

gas in-place324 with 437 tcf technically recoverable.325 This ranks Australia seventh out of the

41 countries reviewed for shale gas resources.326 Western Australia reportedly holds the fifth

largest reserves of shale gas in the world, with a total of 280 tcf.327 The Canning Basin contains

235 tcf of technically recoverable gas.328

https://acola.org.au/wp/PDF/SAF06Consultants/AWTShale%20Gas%20Prospectivity%20Potential%20Jan201

3.pdf 319 Geoscience Australia, Gas, Summary, (accessed 12 May 2017) at www.ga.gov.au/aera/gas 320 Frogtech Pty Ltd, Potential Geological Risks Associated with Shale Gas Production in Australia, Melbourne:

Australian Council of Learned Academics, 2013, pg 2 at

http://www.acola.org.au/PDF/SAF06FINAL/Frogtech_Shale_Gas_Geology_and_Risks%20Jan2013.pdf 321 US Energy Information Administration, Technically Recoverable Shale Oil and Shale Gas Resources: China,

September 2015, pg 3 at https://www.eia.gov/analysis/studies/worldshalegas/pdf/China_2013.pdf 322 Ibid. 323 US Energy Information Administration, Technically Recoverable Shale Oil and Shale Gas Resources: An

Assessment of 137 Shale Formations in 41 Countries Outside the United States, 2013 at

http://www.eia.gov/analysis/studies/worldshalegas/ 324 ‘The technically recoverable resource estimate for shale gas in the report is established by multiplying the

risked gas in-place by a shale gas recovery factor, which incorporates a number of geological inputs and analogs

that are appropriate to each shale gas basin and formation. The risked gas in-place estimate is derived by first

estimating the amount of ‘gas in-place’ resource for a prospective area within the basin, and then de-rating that

gas in-place by factors that account for the current level of knowledge of the resource and the capability of the

technology to eventually tap into the resource’ at http://www.greencarcongress.com/2011/04/eia-

20110406.html 325 Norton Rose Fulbright, Shale gas handbook, A quick-reference guide for companies involved in the

exploitation of unconventional gas resources, June 2015, pg 23 at

http://www.nortonrosefulbright.com/files/norton-rose-fulbright-shale-gas-handbook-108992.pdf , 326 Ibid. 327 Department of Mines and Petroleum, Natural Gas from Tight Rocks (accessed 17 June 2017) at

http://www.dmp.wa.gov.au/Petroleum/Natural-gas-from-shale-and-tight-1591.aspx 328 Ibid.

57

The following map shows the location of Australia’s shale and tight gas sedimentary basins:

Figure 5 Size and extent of Australia’s basins329

The Canning Basin which is located 1500 kilometres northeast of Perth (in Western Australia),

has an onshore area of about 530 000 square kilometres.330 The basin has several organic-rich

shales, including the Laurel and Lower Anderson shales and the large Goldwyer shale.331 The

basin holds 1,227 tcf risked shale gas and shale oil resources in place of which 225 tcf is

technically recoverable.332 It is estimated that there is an additional 38 tcf of recoverable shale

gas in the Laurel formation.333

329 Commonwealth of Australia (Geoscience Australia) 2013. This product is released under the Creative

Commons Attribution 3.0 Australia Licence 330 Department of Mines and Petroleum, Summary of Petroleum Prospectivity: Canning Basin, at

http://www.DMIRS.wa.gov.au/documents/AREA_SUMMARY_CANNING.pdf 331 United States Energy Information Administration, Independent Statistics & Analysis, Technically

Recoverable Shale Oil and Shale Gas Resources: An Assessment of 137 Shale Formation in 41 Countries

Outside the United States, III-28 at < https://www.eia.gov/analysis/studies/worldshalegas/pdf/overview.pdf> 332 Id at III-16. 333 Cook, P, Beck, V, Brereton, D, Clark, R, Fisher, B, Kentish, S, Toomey, J and Williams, J (2013). Securing

Australia’s Future – Engineering energy: unconventional gas production,pg 29 at

http://www.acola.org.au/index.php/projects/securing-australia-s-future/project-6

58

The Cooper Basin in north-east South Australia and south-west Queensland334 covers around

121 382 square kilometres.335 The basin contains three major troughs in the Roseneath Epsilon

Murteree (REM). The REM contains 325 tcf of risked gas in place.336 The REM has three

formations; the Nappamerri, Patchawarra and Tenappera337 which holds 93 tcf of technically

recoverable shale gas.338 The 93 tcf cubic feet comprises 89 tcf in the Nappamerri; 4 tcf

recoverable in the Pathawarra and 0 recoverable in the Tenappera.339

The REM is likely to be Australia’s most easily developed basin340 and its only shale gas sweet

spot.341 The REM is suitably mature for hydrocarbon generation, ‘with laterally extensive thick

intervals and a lithotype that is organic-rich (usually more than 2% organic matter) with a low

clay content.’342 The REM is a recognised natural gas region given it has existing

infrastructure.343 There are over 5000 kilometres of pipelines connecting the Cooper Basin to

gas markets in eastern and southern state capitals and to a liquid load out facility at Port

Bonython.344 Given there is currently uninterrupted pipeline access to gas markets in New

South Wales, Queensland and South Australia, and there is obvious potential for domestic or

export use.345

334 Santos, Cooper Basin (overview) (accessed 15 June 2017) at http://www.santos.com/our-activities/eastern-

australia/cooper-basin-overview-.aspx 335 Frogtech, Potential Geological Risks Associated with Shale Gas Production in Australia, January 2013 at

<http://www.acola.org.au/PDF/SAF06FINAL/Frogtech_Shale_Gas_Geology_and_Risks%20Jan2013.pdf> 336 Id at Attachment C-1. 337 United States Energy Information Administration, Independent Statistics & Analysis, Technically

Recoverable Shale Oil and Shale Gas Resources: An Assessment of 137 Shale Formation in 41 Countries

Outside the United States, III-28 at < https://www.eia.gov/analysis/studies/worldshalegas/pdf/overview.pdf> 338 Ibid 339 Above, note 325 at Attachment C-1. 340 Ibid . 341 Energy Quest, Encouraging signs for Australian shale gas, 16 July 2011 at

http://www.energyquest.com.au/insightsandanalysis.php?id=103 342 Kane Rawsthorn, Shale Gas Prospectivity Potential, AWT International, Prepared for: Australian Council of

Learned Academies, 23 January 2013, pg 12 at

https://acola.org.au/wp/PDF/SAF06Consultants/AWTShale%20Gas%20Prospectivity%20Potential%20Jan201

3.pdf 343 Santos, Moomba 191 and Beyond, 28 August 2013 at

http://www.santos.com/library/130828_Moomba_191_and_beyond.pdf 344 Department of State Development, Roadmap for Unconventional gas projects in SA, 2012 , pg 178 at

http://www.petroleum.dmitre.sa.gov.au/__data/assets/pdf_file/0008/179621/Roadmap_Unconventional_Gas_P

rojects_SA_12-12-12_web.pdf 345 Kane Rawsthorn, Shale Gas Prospectivity Potential, AWT International, Prepared for: Australian Council of

Learned Academies, 23 January 2013, pg 14 at

https://acola.org.au/wp/PDF/SAF06Consultants/AWTShale%20Gas%20Prospectivity%20Potential%20Jan201

3.pdf

59

The Maryborough Basin is located about 250 kilometres north of Brisbane and covers an

onshore area of 11136.95 square kilometres.346 It has two potential shale gas targets within the

cretaceous Maryborough formation347 that are highly unexplored. The Perth Basin is almost

100 000 square kilometres, most of which lies offshore. The onshore part covers about 45 000

square kilometres.348 The Basin contains two main organic-rich shale formations, the Permian

Carynginia and the Triassic Kockatea.349 The Carynginia formation holds 124 tcf risked and

25 tcf recoverable and the Kockatea holds 44 tcf and 8 tcf recoverable.350 The basin contains

33 tcf recoverable (shale gas) in Kockatea, Carynginia and Irwin Formations and 12 tcf (tight

gas) in the High Cliff, Dongara and Wagina Sandstones.351

The Georgina Basin is 323 749 square kilometres352 and is a largely unexplored basin located

in Northern Australia. The basin overlaps the Northern Territory and Queensland border.353

The L. Arthur shale (Dulcie Trough) holds 41 tcf risked and 8 tcf recoverable whilst the L.

Arthur shale (Toko Trough) holds 27 tcf risked and 5 tcf recoverable. 354

The Beetaloo Basin is a 36 260 square kilometre rift basin located in the Northern Territory,

approximately 640 kilometres southeast of Darwin. The basin outline is defined by the Walton

High to the north, the Helen Springs High in the south, and the Batten Trough in the east. Its

western margin is projected to extend to the Daly Waters Arch.355 The M. Velkerri shale holds

346 United States Energy Information Administration, Independent Statistics & Analysis, Technically

Recoverable Shale Oil and Shale Gas Resources: An Assessment of 137 Shale Formation in 41 Countries

Outside the United States, III-28 at < https://www.eia.gov/analysis/studies/worldshalegas/pdf/overview.pdf> 347 Ibid. 348 Department of Mines and Petroleum, Western Australia’s Petroleum and Geothermal Explorer’s Guide –

2014 Edition, pg 54 at < http://www.dmp.wa.gov.au/Documents/Petroleum/PD-RES-PUB-100D.pdf> 349 United States Energy Information Administration, Independent Statistics & Analysis, Technically

Recoverable Shale Oil and Shale Gas Resources: An Assessment of 137 Shale Formation in 41 Countries

Outside the United States, III-20 at < https://www.eia.gov/analysis/studies/worldshalegas/pdf/overview.pdf 350 Id at Attachment C-1. 351 Department of Mines and Petroleum, Submission to the Legislative Council Standing Committee on

Environment and Public Affairs: ‘Inquiry into the Implications for Western Australia of Hydraulic Fracturing

for Unconventional Gas’, 2013, pg 8, at

http://www.parliament.wa.gov.au/Parliament/commit.nsf/(Evidence+Lookup+by+Com+ID)/C4EBD44EB7D2

9B4848257C40000F2471/$file/ev.fra.131003.sub.105.department+of+mines+and+petroleum.pdf 352 United States Energy Information Administration, Analysis and Projections, World Shale Resource

Assessments, 2015 at http://www.eia.gov/analysis/studies/worldshalegas/ 353 Ibid. 354 Id at Attachment C-1. 355 Id at III-40.

60

94 tcf risked and 22 tcf recoverable whilst the L. Kyalla shale holds 100 tcf risked and 22 tcf

recoverable.356

Colorado’s Potential Gas Committee recently assessed the United States’ natural gas resources

determining that it held a total technically recoverable resource of 2,515 tcf.357 The assessment

of 2,515 tcf includes 2357 tcf of gas potentially recoverable from “traditional” reservoirs

(conventional, tight sands and carbonates, and shales).358 The 9.6-tcf (2.3%) net increase for

the Rocky Mountain area resulted from the re-examination of new data and drilling results

from the Cretaceous Niobrara shale play in western Colorado’s Piceance basin and the Niobrara

fractured-carbonate play in the Denver basin.

The Wattenberg Gas Field (WGF) in the Denver-Julesburg Basin in northeast Colorado covers

roughly 81 townships (1.9 million acres).359 In 2006, the WGF was the seventh largest gas

field in the United States and the largest gas producing field in Colorado.360 Current production

is ≈1.2 billion cubic ft (equivalent) per day (Bcfe/d) from over 13,000 producing wells and

cumulative production to date is ≈4.2 tcf (equivalent). Along with the WGF, Colorado contains

the Hilliard-Baxter-Mancos, the Lewis shale, the Mancos shale and the Piceance basin.

The Hilliard-Baxter-Mancos is roughly 42 517 square kilometres and has an average expected

ultimate recovery (EUR) of 0.18 billion cubic feet per well and approximately 3.77 tcf of

technically recoverable gas.361 The Lewis is roughly 19 440 square kilometres and has an

average estimate ultimate recovery of 1.3 billion cubic feet per well and roughly 11.6 tcf feet

of technically recoverable gas.362 The Mancos has been assessed as being roughly 17 065

square kilometres and (excluding the Masaverde, Wasatch and other formations in the Uinta

356 Id at Attachment C-1. 357 Potential Gas Committee, Potential Gas Committee reports increase in magnitude of United States Natural

Gas Resource Base, (accessed 7 May 2017) at http://potentialgas.org/press-release 358 Ibid. 359 Wattenberg Gas Field, USA Region, South Rockies Business Unit DJ Basin Team. Encana – energy for

people,(accessed 19 June 2016) at https://www.erieco.gov/DocumentCenter/Home/View/384 360 Ibid. 361 United States Energy Information Administration, Review of Emerging Resources: United States Shale Gas

and Shale Oil Plays, July 2011, at http://www.ourenergypolicy.org/wp-content/uploads/2013/02/usshaleplays-

1.pdf 362 United States Energy Information Administration, Review of Emerging Resources: United States Shale Gas

and Shale Oil Plays, July 2011, at http://www.ourenergypolicy.org/wp-content/uploads/2013/02/usshaleplays-

1.pdf

61

basin) and when assessed in 2011 had a EUR of roughly 1.0 billion cubic feet per well and was

estimated to have 21.02 tcf of technically recoverable gas.363 The United States Geological

Survey determined that the Mancos Shale in Piceance Basin contained an estimated mean of

of 66 tcf of shale natural gas.364 The Piceance basin is roughly 17 065 square kilometres and

contains between 1.8 tcf and 4.9 tcf. The mean estimated resource is 3.1 tcf of natural gas.365

Western Australia, South Australia and Colorado all have large shale and tight deposits. As

pointed out by Dr Nina Triche, significant resource estimates can create unrealistic commercial

viability expectations.366

2.2.5 Water volume, its role and availability

2.2.5.1 Volume

The demand for water to carry out hydraulic fracturing is placing pressure on water sources in

some regions.367 As well as being used to carry out hydraulic fracturing, water is used during

drilling to cool drill bits and to assist in transferring drill cuttings to the surface.368 The DMIRS

estimate that a vertical well with three fracture stages averages seven million litres of water per

well, comprising one million litres for drilling and six million litres for hydraulic fracturing.369

A horizontal well (with a horizontal length of 1 km) with ten fracture stages averages 21 million

litres of water per well; one million litres for drilling and 20 million litres for hydraulic fracture

stimulation.370 In the United States a single well stage fracture requires roughly 2000 kilolitres

363 Ibid. 364 USGS, USGS Estimates 66 Trillion Cubic Feet of Natural Gas in Colorado’s Mancos Shale Formation,

(accessed 12 May 2017) at https://www.usgs.gov/news/usgs-estimates-66-trillion-cubic-feet-natural-gas-

colorado-s-mancos-shale-formation 365 Above, note 350. 366 Dr Nina Triche, Unconventional Resources: Applying the World To (Western Australia), Water Management

for Shale and Tight Gas Resources, June 8-9, 2015 – Perth, Western Australia 367 Pam Boschee, Produced and Flowback Water Recycling and Reuse, 2014 at

<http://www.halliburton.com/public/multichem/contents/Papers_and_Articles/web/Feb-2014-Oil-Gas-Facilities-

Article.pdf> 368 Colorado Oil and Gas Association, Water use fast facts, (accessed 12 February 2017) at www.coga.org 369 Department of Mines, Industry Regulation and Safety, Guide to the Regulatory Framework for Shale and

Tight Gas in Western Australia, A Whole of Government Approach, 2015 Edition, pg 28 at

http://www.parliament.wa.gov.au/publications/tabledpapers.nsf/displaypaper/3913541ae03e783bf52cf5b94825

7ee5000a9d20/$file/3541.pdf 370 Ibid.

62

(1000 litres = 1 kilolitre (kl) of water).371 In Colorado, a standard well requires around five

million gallons of water to drill and fracture, depending on the basin and geological

formation.372

The volume of water needed to exploit shale and tight gas in dry areas where there is increasing

competition for limited water supplies will likely lead to a shortage of water (and increased

cost) for irrigation, livestock watering, residential use.373 A substantial amount of water is

required to produce shale and tight gas in commercial quantities and it varies significantly from

project to project and is often determined by the size and length of a well and the type of rocks

being fractured. It is estimated that an average of 20 mega litres of water is used per horizontal

well, filling about eight average Olympic sized swimming pools.374 In the United States the

median volume of water exploited per shale gas well in the Barnett shale is 10 600 kilolitres,

in the Haynesville shale 21 500 kl’s , in the Eagleford shale 16 500 kl’s and in the Marcellus

shale 17 100 kl’s.375 The United Nations estimate that a single horizontal well will use between

11 and 34 million litres of water.376 In the United States operators report recycling capacity of

up to 1.5 million barrels of water per day and have recycled up to 50 million barrels of water

since 2012.377

371 Department of Mines, Industry Regulation and Safety, Hydraulic fracture stimulation – water use and

management, (accessed 19 September 2017) at http://dmp.wa.gov.au/Petroleum/Hydraulic-fracture-

stimulation-20057.aspx 372 Accenture, Water and Shale Gas Development, Leveraging the US experience in new shale developments,

(accessed 14 June 2017) at http://www.accenture.com/SiteCollectionDocuments/PDF/Accenture-Water-And-

Shale-Gas-Development.pdf 373 National Energy Technology Laboratory, Modern Shale Gas Development in the United States: An Update,

U.S Department of Energy, September 2013 374 Gas Industry Social & Environmental Research Alliance, (accessed 10 June 2017) at

http://www.gisera.org.au/ 375 P Cook, V Beck, D Brereton, R Clark, B Fisher, S Kentish, J Toomey and J Williams, Engineering Energy:

Unconventional Gas Production, Report for the Australian Council of Learned Academies, May 2013, p 35 at

<https://acola.org.au/wp/PDF/SAF06FINAL/Final%20Report%20Engineering%20Energy%20June%202013.pd

f> 376UNEP Global Environmental Alert Service, Gas Fracking: Can we safely squeeze the rocks?, (accessed 12

March 2017) at http://na.unep.net/geas/archive/pdfs/GEAS_Nov2012_Fracking.pdf 377 Water Conservation and Recycling Symposium, (accessed 18 March 2017) at

http://www.rrc.state.tx.us/about-us/commissioners/craddick/water-recycling-symposium/

63

According to DMIRS, an 18 hole golf course requires between 360 000 and 550 000 kl’s of

water per annum.378 Other activities that require the same amount of water as a 10 stage

fracture well include:

‘1,100 head of cattle or 11,000 head of sheep for a year; irrigating just under 1 hectare

of lucerne, or a 1 hectare commercial sized market garden for one year; 8 Olympic sized

swimming pools; the amount of water used by 45 domestic garden bores in the Perth

metro area, maintaining Domain Stadium’379

2.2.5.2 The role of water

The water that operators need to exploit shale and tight gas will be surface water from streams,

ponds or lakes; groundwater from aquifers or water from alternative sources i.e., drainage

water, recycled water or water trucked in from offsite. The risks and challenges in securing

this water during dry periods will likely see operators competing directly with agricultural and

domestic water users. It is highly likely that shale and tight gas exploitation will adversely

impact water resources beyond production zones and production periods and, given

groundwater is becoming an increasingly important water supply source worldwide,

understanding the amount of groundwater used versus the volume available is vital in order to

evaluate future water availability.

There are a myriad of issues that require management, including but not limited to, the volume

of water used for hydraulic fracturing; the protection of potable aquifers and the handling of

produced water.380 In general operators use more water for horizontal wells compared to

vertical wells given they require more fracture stages and additional stages of hydraulic fracture

stimulation result in the need for greater volumes of water and longer and more complex

fracture patterns require more water. The larger the number of naturally occurring fractures in

the rock formation, the less hydraulic fracture stimulation is required. An operator may decide

378 Department of Mines, Industry Regulation and Safety, Hydraulic fracture stimulation – water use and

management, (accessed 17 June 2016) at http://dmp.wa.gov.au/Petroleum/Hydraulic-fracture-stimulation-

20057.aspx 379 Ibid. 380 Frogtech, Potential Geological Risks Associated with Shale Gas Production in Australia, January 2013, pg 4

at http://www.acola.org.au/PDF/SAF06FINAL/Frogtech_Shale_Gas_Geology_and_Risks%20Jan2013.pdf

64

to re-fracture an existing well during its production life which requires water for hydraulic

fracture stimulation activities.

Water is also needed for accommodation, dust suppression, construction and related

activities.381 The significant amount of water required almost certainly leads to issues of

competition382, i.e., competition between operators, farmers and domestic water users.383 The

demand for freshwater, the production of wastewater and groundwater contamination are all

areas of concern.384 Concern is likely to be greatest when there are competing demands from

water users (for example from urban and agricultural development) and declining water in

aquifers.385

2.2.5.3 Water availability

The bulk of Australia’s shale and tight gas reserves are located in areas of medium to high

drought severity and medium to high seasonal variability in water supplies.386 The arid

conditions in the Canning Basin and Cooper Basin will likely result in significant regulatory

challenges.387 The health of the world’s aquifers was considered with the release of satellite

data by the National Aeronautics and Space Administration (NASA).388 The data showed

that the Canning basin has the third-highest rate of depletion in the world with the Great

Artesian Basin (GAB) amongst the healthiest.389 The authors of the study contend that mining

activities in the rural Canning Basin are possibly influencing the GRACE signal.390

381 Department of Mines and Petroleum, Guide to the Regulatory Framework for Shale and Tight Gas in

Western Australia, A Whole of Governmenr Approach, 2015 Edition, pg 28 382 National Water Commission, Canberra, Water for mining and unconventional gas under the National Water

Initiative, 2014, pg 1 383 Paul Reig, Tianyi Luo, and Jonathan N. Proctor, World Resources Institute, Global Shale Gas Development,

Water Availability and Business Risks, (2014) at 50 at

http://www.wri.org/sites/default/files/wri14_report_shalegas.pdf 384 Shale Gas Information Platform, What are the risks?, (accessed 10 May 2017) at http://www.shale-gas-

information-platform.org/what-are-the-risks.html 385 Rahm, B, G and Riha, S, J, ‘Evolving shale gas management: water resource risks, impacts, and lessons

learned’ (2014) 16 Environ. Sci: Processes Impacts 1400, 1401 at

http://pubs.rsc.org/en/content/articlepdf/2014/EM/C4EM00018H 386 Paul Reig, Tianyi Luo and Jonathan N. Proctor, ‘Global Shale Gas Development – Water Availability and

Business Risks’, World Resources Institute, 2014, 50 387 Ibid. 388 Richey, A. S., B. F. Thomas, M.-H. Lo, J. T. Reager, J. S. Famiglietti, K. Voss, S. Swenson, and M.

Rodell, ‘Quantifying renewable groundwater stress with GRACE’ (2015) Water Resources. Res. 51 389 Ibid. 390 Id at 5228.

65

Groundwater is becoming an increasingly important water supply source worldwide and

understanding the amount of groundwater used versus the volume available is vital in order to

evaluate future water availability.391

The use of groundwater for hydraulic fracturing will have an effect on the environment and

other water users.392 It is likely that the risk in securing water for production during dry periods

will lead to increased operational and reputational risks for operators who will have to compete

for scarce resources with both agricultural and domestic water users.393 It is also likely that

shale and tight gas production will negatively impact water resources beyond production zones

and production periods given significant amounts of water are used to facilitate exploitation.394

Some industry commentators argue that operators in Western Australia and South Australia

will need to rely on slowly recharged groundwater.395 Those operating in the Canning Basin

and Cooper Basin will be key consumers of groundwater relative to sustainable extraction

levels.396 Groundwater is becoming an increasingly important water supply source worldwide

and understanding the amount of groundwater used versus the volume available is vital in order

to evaluate future water availability.397

The GAB is one of the largest underground water reservoirs in the world and covers

approximately 22 percent of Australia.398 The GAB covers most of Queensland, the Northern

Territory, New South Wales and parts of South Australia to depths of up to 3000 metres and

391 Id at 51. 392 Frogtech, Potential Geological Risks Associated with Shale Gas Production in Australia, January 2013, pg 4,

at http://www.acola.org.au/PDF/SAF06FINAL/Frogtech_Shale_Gas_Geology_and_Risks%20Jan2013.pdf 393 Paul Reig, Tianyi Luo and Jonathan N. Proctor, ‘Global Shale Gas Development – Water Availability and

Business Risks’, World Resources Institute, 2014, 50 394 IHS Cambridge Energy Research Associates in their report Fuelling North America’s Energy Future – The

Unconventional Natural Gas Revolution and the Carbon Agenda, (2010) at

https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/43227/1296-ihs-cera-special-

report.pdf 395 Frogtech, Potential Geological Risks Associated with Shale Gas Production in Australia, January 2013, pg 4,

at http://www.acola.org.au/PDF/SAF06FINAL/Frogtech_Shale_Gas_Geology_and_Risks%20Jan2013.pdf 396 Ibid. 397 Richey, A. S., B. F. Thomas, M.-H. Lo, J. T. Reager, J. S. Famiglietti, K. Voss, S. Swenson, and M.

Rodell ’Quantifying renewable groundwater stress with GRACE’ (2015) Water Resources. Res. 51, 398 Department of Environment, Great Artesian Basin, (accessed 12 October 2017) at

http://www.environment.gov.au/water/environment/great-artesian-basin

66

is approximately 1.7 million square kilometres and stores around 65 000 gigalitres of water.399

The GAB contains various geological basins ranging in age from 200 years to 65 million years

which sit above deeper, older geological basins that have newer surface drainage divisions such

as Lake Eyre and Murray-Darling river basins situated on top of them.400 There are six major

aquifers in the GAB that have an average thickness of 150-200 metres and are mostly

sandstones recharged by rainfall with stream flows penetrating the exposed sandstones on the

eastern edge of the basin. The deepest aquifer, the Hutton Sandstone, extends to a depth of

approximately 3000 metres in the Cooper Basin region.

The Cooper Basin is covered by the Hutton Sandstone aquifer which has shale layers beneath

it that are close to freshwater aquifers.401 The division between the GAB and the highly

prospective gas is inconsistent and ranges from 300-800 metres.402 The GAB is separated from

gas by a number of low permeability beds the most significant of which is the Triassic

Nappamerri Group (‘Nappamerri’).403 This bed is up to 500 metres thick. The Nappamerri is

mainly siltstone; though it does contain areas that have higher permeability sandstone beds

which have the potential to act as pathways between the Cooper Basin and the GAB.404

The Canning Superbasin is Australia’s second largest aquifer.405 The Canning Super Basin is

restocked by rainwater ensuring there is water available all year round.406 The aquifer provides

water for pastoral use, drinking water and industry throughout the Kimberley. The aquifer

399 Cook, P, Beck, V, Brereton, D, Clark, R, Fisher, B, Kentish, S, Toomey, J and Williams, J (2013). Securing

Australia’s Future – Engineering energy: unconventional gas production,pg 124 at

http://www.acola.org.au/index.php/projects/securing-australia-s-future/project-6 400 Smerdon, B. D., Marston, F. M., & Ransley, T. R. (Water resource assessment for the Great Artesian Basin.

Australia: Synthesis of a report to the Australian Government from the CSIRO Great Artesian Basin Water

Resource Assessment. (CSIRO Water for a Healthy Country Flagship, Australia, 2012). 401 Stephanie Neitzel, P.E. Esq. Principal WaterRich Advisors LLC, Centennial, Colorado, Water quality

regulations for unconventional gas production, United States and Australia comparison, (accessed 14 June

2017) pg 7 at http://www.awa.asn.au/documents/136%20SNeitzel.pdf 402 Gravestock, D.I., Hibburt, J.E. and Drexel, J.F. (eds), The petroleum geology of the SA. Volume 4: Cooper

Basin Report Book 98/9(Primary Industries and Resources SA (PIRSA), 1st Edition, November 1998) at

http://www.petroleum.statedevelopment.sa.gov.au/home/access_to_data/petroleum_publications/petroleum_geo

logy_of_south_australia/vol_4_-_cooper_basin_downsampled 403 Frogtech, Potential Geological Risks Associated with Shale Gas Production in Australia, January 2013, pg 10

at http://www.acola.org.au/PDF/SAF06FINAL/Frogtech_Shale_Gas_Geology_and_Risks%20Jan2013.pdf 404 Above, note 390. 405 Buru Energy, Hydraulic Fracturing, (accessed 27 July 2016) at http://www.buruenergy.com/canning-

basin/hydraulic-fracturing-2/ 406 Ibid.

67

recharge from annual rainfall is 827 000 mega litres a year whilst domestic water supply for

Broome is approximately 5400 mega litres a year.407

The Canning Super Basin is unique, in that less than 1 percent of the aquifer is covered by

residential areas, though it has the third highest rate of GRACE-derived depletion (−9.40 ± 1.34

mm/yr).408 It has been suggested that mining activities in the rural Canning Basin are likely

influencing the GRACE signal which is lost in the statistics-based use rate of −0.002 mm/yr.409

The renewable groundwater stress ratio, quantified according to a ratio of groundwater use to

availability, in the Canning Super Basin is −1.6, which implies that about 150 percent more

water is depleted than is naturally available and water in storage is used to supplement available

supplies. In reality, storage loss and environmental degradation can occur when the renewable

groundwater stress is less than one.410

Some industry commentators suggest that, if extensive gas extraction occurs in the Canning

Super Basin, alternatives to fresh water; such as saline water, reuse/recycling and non-water

based fracking fluids will need to be considered.411 In contrast, Buru stated that in 2014, it was

licenced to take up to 50 mega litres per annum of water at each of its well sites as part of its

tight gas pilot program.412 Buru estimated that 31 mega litres of water was required for

hydraulic fracturing which represented less than 0.005 percent of the annual sustainable yield

of the basin or less than two days water use for the town of Broome.413 According to Buru, if

the aquifer annual recharge from rainfall was equal to a 205 litre drum, then the forecast annual

water use of 31 mega litres would equate to less than a teaspoon, compared to the West

Kimberley region’s household water use which equates to a 10 litre bucket.414 Buru estimated

that the maximum total water usage for the four wells in the program is less than eight days’

407 Buru Energy, Buru Energy’s proposed gas developments in the Canning Basin – Questions and Answers,

March 2014, pg 13 at http://www.buruenergy.com/wp-content/uploads/Proposed-Gas-Developments-QA1.pdf 408 Richey, A. S., B. F. Thomas, M.-H. Lo, J. T. Reager, J. S. Famiglietti, K. Voss, S. Swenson, and M. Rodell,

‘Quantifying renewable groundwater stress with GRACE’ (2015) Water Resources. Res. 51 409 Ibid. 410 Ibid. 411 Frogtech, Potential Geological Risks Associated with Shale Gas Production in Australia, January 2013 at

<http://www.acola.org.au/PDF/SAF06FINAL/Frogtech_Shale_Gas_Geology_and_Risks%20Jan2013.pdf, pg

17> 412 Buru Energy, Hydraulic Fracturing, (accessed 3 June 2016) at http://www.buruenergy.com/canning-

basin/hydraulic-fracturing-2/ 413 Above, note 395. 414 Buru Energy, Buru Energy’s proposed gas developments in the Canning Basin – Questions and Answers,

March 2014, pg 13 at <http://www.buruenergy.com/wp-content/uploads/Proposed-Gas-Developments-

QA1.pdf >

68

water use by the town of Broome or less than the water required to irrigate 1 hectare of crop

annually.415

Operators in Western Australia and South Australia will face significant risk and challenges

when they seek to use water to exploit shale and tight gas in the Canning and Cooper Basins.

Amongst other things, they will need to protect water sources from contamination and consume

an amount of water that the community finds palatable. Any demands operators place on

communities for fresh water to carry out hydraulic fracturing will likely be opposed. The large

volumes required will result in significant competition, between themselves, local inhabitants

and agricultural interests. Having in place appropriate regulatory regimes to deal with water

management is imperative.

2.3 Literature review: Community concerns with regulatory issues

According to some industry commentators, ‘there exists little knowledge of or established

consensus on best practice around the governance of unconventional gas development.’416 The

widespread hostility to shale and tight gas exploitation in the United States, in particular, is

mainly due to concerns about the impact on water.417 Not surprisingly, governments all over

the world are under considerable pressure to develop regulatory regimes that are accepted, first

and foremost, by the community.418

One industry commentator insists that the environmental risks linked to shale and tight gas

exploitation, including from hydraulic fracturing can be managed subject to the establishment

of robust regulatory regimes.419 Shale and tight gas production is often characterised by the

415 Buru Energy, Hydraulic Fracturing, (accessed 3 June 2016) at http://www.buruenergy.com/canning-

basin/hydraulic-fracturing-2/ 416 Jarvis, M, ‘Towards a Roadmap for Governance of Unconventional Gas: A Multidimensional Challenge’

(2014) 12:3 Oil, Gas & Energy Law at < https://www.ogel.org/article.asp?key=3464> (assessed 23 November

2017) 417 Accenture, Water and Shale Gas Development – Leveraging the US experience in new shale developments’,

2012, 5 at <http://www.accenture.com/SiteCollectionDocuments/PDF/Accenture-Water-And-Shale-Gas-

Development.pdf> 418 Brian G. Rahm & Susan J. Riha ‘Evolving Shale Gas Management: Water resource

risks, impacts, and lessons learned’ (2014), Environ. Sci. Processes Impacts 1400, 1408 at

<http://pubs.rsc.org/en/content/articlepdf/2014/EM/C4EM00018H> 419 Allan Hawke AC, Report of the Independent Inquiry into Hydraulic Fracturing in the Northern Territory,

2014, Executive Summary, page x.

69

use of ‘old oil and gas regulations…because they have worked in the past’.420 The literature

clearly articulates that ‘shale gas development, particularly its rapid pace and large scale, brings

with it new risks, and new variations of old risks’.421 Some industry commentators contend

that using existing regulation designed to exploit conventional gas is unacceptable, as is the

approach of simply adjusting it.422

The community concern with the exploitation of shale and tight gas and land access, water

access and quality protection, regulation of well technology for drilling and hydraulic fracking

and decommissioning and associated issues (abandonment, rehabilitation and reclamation) has

been expressed in a number of recent parliamentary inquiries in Western Australia and South

Australia.423 It is highly likely the community and political antagonism toward shale and tight

gas exploitation (particularly in Western Australia) will continue unless satisfactory

alternatives are developed. There are numerous international studies that have examined the

risks and challenges associated with exploiting shale and tight gas, though the author argues

that none have dealt in a meaningful way with the specific shortcomings and regulatory gaps

that the thesis contends exist in Western Australia and South Australia.

The majority of international studies have examined the United States’ experience as a way of

informing emerging nations of the conditions that helped them elicit a shale gas boom.424

Others concentrate on the negative impacts of shale and tight gas exploitation, for example,

water consumption, contamination, and land use and landscape issues.425 A number argue that

there are significant regulatory challenges with regard to well spacing, hydraulic fracturing,

water management, landowner concerns, public concerns, environmental issues, regulatory

420 Above, note 406 at 1409. 421 Ibid. 422 Simon Robb, A Best Practice Regulatory Proposal for Shale Gas Production, The University of Western

Australia, 2014, pg 11 423 Standing Committee on Environment and Public Affairs, Parliament of Western Australia, Report 42,

Implications for Western Australia of Hydraulic Fracturing for Unconventional Gas, November 2015 at

http://www.parliament.wa.gov.au/Parliament/commit.nsf/(Report+Lookup+by+Com+ID)/74E61E739E39E57

748257EF9002150FE/$file/ev.fra.151117.rpf.042.xx.pdf and Natural Resources Committee, Inquiry into

Unconventional Gas (Fracking) in the South East of SA, Final Report, One Hundred Nineteenth Report of the

Natural Resources Committee, Tabled in the House of Assembly and ordered to be published 29 November

2016 at https://www.parliament.sa.gov.au/Committees/Pages/Committees.aspx?CTId=5&CId=341 424 Wang, Z. & Krupnick, A., A Retrospective Review of Shale Gas Development in the United States: What

Led to the Boom?, 2013 at http://www.rff.org/RFF/Documents/RFF-DP-13-12.pdf 425 Tim Boersma & Corey Johnson, Risks and Potentials of Shale Gas Revolution, Consequences for Markets

and the Environment, German Institute for International and Security Studies, SWP Comments 39, December

2012, pg 4.

70

processes, and information collection and dissemination.426 With respect, Western Australia

and South Australia’s regulatory regimes are under-analysed and there are limited academic

studies on the particular issues outlined in this thesis’ introductory chapter (and above). Given

that shale and tight exploitation is in its infancy in Western Australia and South Australia,

understanding all the risk and challenges associated with it is difficult.427

Several years ago, one study concluded, quite rightly, that the literature on shale and tight gas

exploitation ‘on countries outside the United States and a few European states was rather

thin’.428 This shortcoming prompted the study’s author to call for papers on the topic of

governance of unconventional gas outside the United States for publication.429 Of those

received on the topic, none dealt with the myriad of issues examined in this thesis in the context

of Western Australia and South Australia.430

The development of roadmaps and frameworks assist in guiding operators and informing

stakeholders of the step-by-step process for potential development and the various 'good

governance' interventions required at each stage of the value chain.431 Both Western Australia

and South Australia have released these documents in the last few years - the Roadmap for

Unconventional Gas Projects in SA432 and Guide to the Regulatory Framework for Shale and

Tight Gas in Western Australia – A Whole of Government Approach. 433

Towards a Roadmap for Governance of Unconventional Gas: A Multidimensional Challenge

argues that there is little knowledge of, or established consensus on best practice around the

426 Energy Resources Conservation Board, Unconventional Gas Regulatory Framework - Jurisdictional Review

(Report 2011-A), 2011 at https://www.aer.ca/documents/reports/r2011-A.pdf 427 Brian G. Rahm & Susan J. Riha, ‘Evolving shale gas management: water resource

risks, impacts, and lessons learned’ (2014) 16 Environ. Sci.: Processes

Impacts 1400, 1408 at http://pubs.rsc.org/en/content/articlepdf/2014/EM/C4EM00018H 428 Andrews-Speed, Dr. P, ‘OGEL Special: Governance of Unconventional Gas outside the United States’

(2014) June 12:3 Oil, Gas & Energy Law 429 Oil, Gas and Energy Law Journal (2014) June 12:3 at https://www.ogel.org/ 430 Andreas Goldthau, Michael LaBelle, ‘OGEL Special: Governance of Unconventional Gas in Bulgaria’

(2014) June 12:3 Oil, Gas & Energy Law; Silke M. Popp, OGEL Special: Unconventional Gas Regulation in

Canada’ (2014) June 12:3 Oil, Gas & Energy Law 431 Jarvis, M, ‘Towards a Roadmap for Governance of Unconventional Gas: A Multidimensional Challenge’,

(2014) June 12:3 Oil, Gas & Energy Law 432 Energy Resources Division, Department of Manufacturing, Innovation, Trade, Resources and Energy,

Roadmap for Unconventional Gas Projects in SA, 2012 at https:///www.statedevelopment.sa.gov.au 433 [Department of Mines and Petroleum, Guide to the Regulatory Framework for Shale and Tight Gas in

Western Australia – A Whole of Government Approach, 2015 Edition at https://www.DMIRS.wa.gov.au

71

governance of unconventional gas development globally.434 This is certainly a fair statement.

As pointed out by the Energy Resources Conservation Board, regulatory frameworks must be

adapted to better manage unconventional gas and considerably different approaches are

required if regulations are to remain relevant.435 In Shale Gas: A Review of the Economic,

Environmental and Social Sustainability it is suggested that ‘in many nations, existing oil and

gas regulations are currently thought to be sufficient, but new legislation is being introduced to

tackle problems associated with shale gas that have arisen or could arise’.436 However, the

introduction of new legislation takes time.437

Dr Robb’s regulatory proposal is a useful document for those interested in the exploitation of

shale and tight gas and on matters to which this thesis has referred to, though it is not issue

specific; rather it proposes a new regulatory framework.438 With respect, it does not deal with

specific jurisdictional solutions to land access, water use, drilling, hydraulic fracturing,

decommissioning and rehabilitation explicitly. Western Australia and South Australia are both

unlikely to introduce specific stand-alone unconventional gas legislation any time soon, if at

all. Both jurisdictions have, at various times, amended their conventional gas legislation so

they can manage the exploitation of unconventional gas.

2.3.1 Land Access

The thesis is primarily concerned with private land, leased land (pastoral, agricultural or other),

land subject to a grant of title (petroleum) or native title land.439 For some, the thought of

operators entering their land to exploit shale and tight gas is profoundly distressing. Though

many understand that they do not own the minerals on their land, ‘the realisation that they are

legally required to give access to their land to gas exploration companies and that those

434 Jarvis, M, ‘Towards a Roadmap for Governance of Unconventional Gas: A Multidimensional Challenge’,

(2014) June 12:3 Oil, Gas & Energy Law 435 Eynon, G. et al. Unconventional Resource Development and role of regulator (Energy Resources Conservation

Board) (ERCB) Alberta. (Canadian Society for Unconventional Gas & SPE Committee, October 2010). 436 Jasmin Cooper, Lawrence Stamford, & Adisa Azapagic, “Shale Gas: A Review of the Economic,

Environmental, and Social Sustainability” (2016) 4 Energy Tecnol 772, 785 437 Ibid 438 Simon Robb, ‘A Best Practice Regulatory Proposal for Shale Gas Production’, 2014, Faculty of Law,

University of Western Australia 439 Allnut, Liz, Australia: Rules and regulation of the oil and gas industry: Navigating the governance maze, 14

October 2015, Norton Rose Fulbright Australia

72

companies could, for example, construct roads, clear drilling sites, build work camps and,

ultimately, construct gas production facilities, came as a profound shock.’440

Many Australians, particularly those in farming communities, mistakenly believe they enjoy

an unqualified right to determine exactly who may enter or remain on their land and believe

they exercise a virtually unassailable discretion to exclude individuals from trespassing on that

land.441 This is not the case. There are no laws in Western Australia or South Australia,

constitutional or otherwise, that prohibit the exploration and production of shale and tight gas

if the government considers it to be in the public interest.

In Australia, the multiple land use framework (the framework) recognises land access and land

use conflict.442 The framework asserts that ‘[by] reducing tensions that can arise between

stakeholders, we achieve a better economic, social and environmental outcome that leads to

sustainable outcomes for future generations.’443 The framework features four desired

outcomes, eight principles to guide land access and land use decisions and nine components

that should be considered in planning, preparing and assessing land access and land use

decisions.444 The principles detailed in the framework give operators co-existing rights and

interests with respect to land.445 The framework was established with the resources and energy

sectors in mind with the view that the concept would be extended to all sectors. The principle

highlights that conflict arises according to land use needs and strategic objectives and it aids

groups in addressing these challenges.

Land access regulation is primarily about government attempts to balance the rights of land

holders and operators and to address community-wide costs and benefits that arise from

exploration activities.446 Disputes occur when the rights held by operator’s impact the property

440 Commonwealth Parliament, Senate, Standing Committee on Rural and Regional Affairs and Transport,

Management of the Murray Darling Basin Interim Report: the impact of mining coal seam gas on the

management of the Murray Darling Basin, 30 November 2011, pg 53. 441 Kevin Gray & Susan Francis Gray, ‘The Idea of Property in Land’ in Susan Bright & John K Dewar (eds)

Land Law: Themes and Perspectives (Oxford University Press, (1998) ,15-51 at 16 at https://trin-

hosts.trin.cam.ac.uk/fellows/kevingray/870.pdf 442 Standing Council on Energy and Resources, Multiple Land Use Framework, 13 December 2012, pg 1 443 Id at 6. 444 Standing Council on Energy and Resources, Multiple Land Use Framework, Background Document,

December 2013 at <https://industry.gov.au/resource/Mining/Documents/MLUFBackgrounddocument.docx> 445 COAG Energy Council, Multiple Land Use Framework, (accessed 18 September 2017) at

http://www.scer.gov.au/workstreams/land-access/mluf/ 446 Productivity Commission, Non-Financial Barriers to Mineral and Energy Resource Exploration, 2013, pg 17

73

rights of landowners.447 These issues are often settled by negotiation, i.e., conditions of access

and compensation. It has been suggested that the financial incentive operators provide

(compensation for damage or loss of earnings (or amenity)) minimises the impact of their

activities.448 In Western Australia, South Australia and Colorado, operators who intend to carry

out activities on private land are encouraged to negotiate voluntary land access agreements.449

These types of agreements, particularly in Queensland, have been described, as a ‘peculiar

hybrid of contract, statute and property law.’450 Ideally, access agreements should reduce the

potential negative impacts on landholders.451 Some argue that land access agreements are not

ideal given they are essentially nothing more than a business to business transaction.452 Further

to this point, it is likely that, despite the best efforts of those involved, the following United

Kingdom situation applies in Australia:

…most rural landholders can be at some disadvantage due to: their limited

experience in undertaking such negotiations compared to explorers, who

may have negotiated hundreds of such agreements; the asymmetry of

information regarding the potential impact of the exploration activity; and an

imbalance or power, as in most cases, rural land holders are legally required

to allow explorers to access their land.453

While this thesis is not examining the regulation of shale and tight gas in the United Kingdom,

it is worth noting that they see land access as a real barrier to the industry.454 Some have

recommended that shale gas operators in the United Kingdom should have an automatic right

of access so they can undertake horizontal drilling where it takes place at least 300 metres

447 Ibid. 448 Ibid. 449 Department of Mines, Industry Regulation and Safety, Natural Gas from Shale and Tight Rocks, An

overview of Western Australia’s regulatory framework, February 2014, pg 7

<https://www.DMIRS.wa.gov.au/Documents/Petroleum/PD-SBD-NST-102D.pdf> 450 Sharon Christensen, Pamela O'Connor, W D Duncan & Angela Phillips, ‘Regulation of land access for

resource development: A coal seam gas case study from Queensland’ (2012) 21:110 APLJ, 31 451 AMP Capital, Unconventional Gas Extraction, Its importance in the transition to a low carbon economy,

insight paper, (accessed 18 July 2017) page 2 at

http://www.ampcapital.com.au/AMPCapitalAU/media/contents/Articles/ESG%20and%20Responsible%20Inv

estment/20150210-esg-unconventional-gas-extraction.pdf 452 Productivity Commission, Non-Financial Barriers to Mineral and Energy Resource Exploration, 2013, pg 18

at < https://www.pc.gov.au/inquiries/completed/resource-exploration> 453 Ibid. 454 Ashurst Lawyers, Clearing the road for UK shale gas: a new land access regime (Energy, resources and

infrastructure briefing, May 2014) at https://www.ashurst.com/publication-item.aspx?id_Content=10503

74

below the surface.455 The basis of this right is the existing statutory right to access offered to

coal operators in relation to underground operations.456 Again, while not examining the

regulatory regime of Queensland to manage coal seam gas and land access, it has been

suggested that Queensland’s current statutory regime for land access agreements is disjointed

and does not fit with any established legal rules.457

The erosion, whether it is perceived or actual, of landowner ‘rights’, the strongly held view

that compensation is inadequate and the power imbalances, whether real or perceived, in

negotiations for entry to land for the purposes of shale and tight gas development all have the

potential to lead to significant discontent in the community.458 In order for exploitation to

proceed smoothly, particularly in Western Australia, the issue of land access requires further

examination.

Conflict often arises when the exploration rights held by operators seeking to exploit gas impact

on the property rights held by landowners (or occupiers).459 These conflicts tend to occur more

so when the land is high value agricultural land, land around urban centres and other areas of

high concentration land use.460 Colorado once had the most wells (over 10 000) drilled in

highly productive irrigated cropland and, as a consequence, dealt with a significant number of

community complaints.461 As a result of this conflict, surface owners’ in Colorado strived to

gain greater control over their land and compensation.462

Balancing the conflicting rights of those with an interest in land by addressing community-

concerns associated with exploitation is particularly difficult.463 The erosion of landholder

rights, whether it is simply perceived by landholders or actually happens, the view, particularly

by farmers that compensation is inadequate and the power imbalances between landholders

455 Ibid. 456 Ibid. 457 Ibid. 458 AMP Capital, Unconventional Gas Extraction, Its importance in the transition to a low carbon economy,

insight paper, pg 3

athttp://www.ampcapital.com.au/AMPCapitalAU/media/contents/Articles/ESG%20and%20Responsible%20In

vestment/20150210-esg-unconventional-gas-extraction.pdf 459 Productivity Commission, Non-Financial Barriers to Mineral and Energy Resources Exploration, 2013, pg 17 460 Ibid. 461 John Erich Johnson ‘Gerrity Oil & Gas Corp. v. Magness: Colorado’s Furtive Shift toward Accommodation

in the Surface-Use Debate, Spring 1998’ (2013) 33:3 Tulsa Law Review 462 Ibid. 463 Productivity Commission, Non-Financial Barriers to Mineral and Energy Resource Exploration, 2013, pg 17

75

and operators in negotiations all have the potential to, and often do, lead to significant

discontent in local communities.464 DMIRS may lead the world in regulating shale and tight

gas exploitation because they are ‘professional and have the necessary experience and

processes to implement best practice in the regulation of unconventional natural gas.’465 This

means little to a concerned landholder dealing with an operator. Having the necessary

experience and processes to implement best practice is not enough.

The Standing Committee of Environment and Public Affairs recommended, amongst other

things, that the government draft legislation for a statutory framework for land access

agreements.466 Western Australia’s Parliamentary inquiry determined that the state’s citizens

were nervous about the impact of shale and tight exploitation on agricultural land, native

titleholders and its overall footprint.467 The inquiry recommended that the Western Australia

government establish a working group ‘to draft legislation for a statutory framework for land

access agreements between land owners and resource companies and should include provisions

for an agreement template, compensation for land owners and the enforcement of mandatory

access conditions.’468 The role of the working group is to consider existing land access

provisions for private land, consider other jurisdictions’ land access arrangements for private

land (legislative and non-legislative), suggest changes to Western Australia’s farming land

access agreement and make recommendations on a statutory framework for land access

464 AMP Capital, Unconventional Gas Extraction, Its importance in the transition to a low carbon economy,

insight paper, pg 3 at

http://www.ampcapital.com.au/AMPCapitalAU/media/contents/Articles/ESG%20and%20Responsible%20Inv

estment/20150210-esg-unconventional-gas-extraction.pdf 465 Mining Australia, “WA DMIRS recognised as one of world’s best resource regulators” Australian Mining

news release 3 November 2013 from http://miningaustralia.com.au/news/wa-DMIRS-recognised-as-one-of-

world-s-best-resources 466 Standing Committee on Environment and Public Affairs, Parliament of Western Australia, Report 42,

Implications for Western Australia of Hydraulic Fracturing for Unconventional Gas, November 2015 at

http://www.parliament.wa.gov.au/Parliament/commit.nsf/(Report+Lookup+by+Com+ID)/74E61E739E39E57

748257EF9002150FE/$file/ev.fra.151117.rpf.042.xx.pdf 467 Id at Chapter 5, pg 75. 468 Government of Western Australia, Response to recommendations of the Legislative Council Standing

Committee on Environment and Public Affairs Report No.42 Implications for Western Australia of Hydraulic

Fracturing for Unconventional Gas, 16 March 2016 at <

http://www.parliament.wa.gov.au/publications/tabledpapers.nsf/displaypaper/3913895c7a06d337d5c9ab70482

57f79000e5c77/$file/tp-3895.pdf>

76

agreements.469 The working group was to make a number of recommendations by 31 December

2017.470

The DMIRS considered the signing of a land access agreement in 2015 as historic.471 The

agreement outlines the ‘rights and responsibilities of property owners and petroleum companies

during negotiations over land access, and [will] include information on compensation,

mediation and land rehabilitation’.472 The Environment and Communications Legislation

Committee inquiry into landholder rights was advised that ‘ditches dug for pipe construction

can make it difficult for farmers to traverse their property and can lead to livestock injuries.’473

Landholders described to the Commonwealth inquiry how they faced complications when

dealing with the gas companies, such as instances of discourteous approaches to accessing and

navigating their land’.474

In the United States, shale and tight gas exploitation requires a significant number of small

facilities some of which are, literally, in people’s gardens.475 Furthermore, exploitation is

happening in residential areas and regions not typically accustomed to large scale oil and gas

exploitation.476 According to Professor Samantha Kennedy, in the Australia context, ‘the

exploitation of unconventional gas has generated considerable landowner antagonism’.477 For

example, the Lock the Gate Alliance argue that, amongst other things, the exploitation of

469 Department of Mines and Petroleum, Western Australian Land Access Working Group, Terms of Reference,

(accessed 19 May 2017) at http://www.DMIRS.wa.gov.au/About-Us-Careers/Western-Australian-Land-

Access-20627.aspx 470 Land Access Working Group established, Thursday 15 September 2016 at

https://www.mediastatements.wa.gov.au/Pages/Barnett/2016/09/Land-Access-Working-Group-

established.aspx 471 Department of Mines and Petroleum, New gas agreement for agriculture sector, 3 November 2015 at <

http://www.dmp.wa.gov.au/News/New-gas-agreement-for-16635.aspx> 472 Ibid. 473 Environment and Communications Legislation Committee inquiry into the Landholders’ Right to Refuse

(Gas and Coal) Bill 2015, (2015), pg 13-14 at <

https://www.aph.gov.au/Parliamentary_Business/Committees/Senate/Environment_and_Communications/Gas

_and_Coal/Report> 474 Ibid. 475 Hannah J. Wiseman, ‘Hydraulic Fracturing and Information Forcing’ (2013) 74 Ohio State Law Journal 87-

97 476 Katherine E. Konschnik & Mark K. Boling, ‘Shale Gas Development: A Smart Regulation Framework’

(2014) Environmental Science & Technology A 477 Samantha Hepburn, ‘Does Unconventional Gas Require Unconventional Ownership? An Analysis of the

Functionality of Ownership Frameworks for Unconventional Gas Development’ (2013) 8:1 Journal of

Environmental and Public Health Law 44

77

unconventional gas causes a loss of productive farming land, reduced viability of farming

operations and competition for scarce water resources.478

The Western Australia government has been urged to ‘address the issue of conflicting land use

and land access in its management of shale gas operations throughout the whole petroleum

chain’.479 Dr Hunter argues that these issues should be addressed through legislative provisions

contained within the PGERA (objects clause) and a pre-emptive land use management strategy

developed in consultation with relevant stakeholders and communities.480 To date, none of this

has occurred.

The Environment and Communications Legislation Committee (Federal Parliament), inquiry

received a number of submissions that argued that compensation arrangements failed to deal

with the imbalance in negotiating positions between landholders and operators.481 Some

insisted that the lack of negotiating power was ‘very evident’ and stemmed from an inability

of some farmers to understand the often large amounts of information operators were providing

them.482 One operator is alleged to have offered a landholder $265 to develop wells and

‘associated petroleum infrastructure’.483 The landholder stated that ‘No-one knows what

478 Lock the Gate Alliance, Submission to the Standing Committee on the Environment and Public Affairs

Inquiry into the Implications for Western Australia of Hydraulic Fracturing for Unconventional Gas, (20

September 2013), pg 3 at <

https://www.aph.gov.au/Parliamentary_Business/Committees/Senate/Environment_and_Communications/Gas

_and_Coal/Report> 479 Tina Hunter, Regulation of Shale, Coal Seam Gas and Tight Gas Activities in Western Australia, Final, An

analysis of the capacity of the Petroleum and Geothermal Energy Act 1967 (WA) to regulate onshore gas

activities in Western Australia, July 2011 at < https://epublications.bond.edu.au/law_pubs/419/> 480 Department of Mines and Petroleum Response to Report: ‘Regulation of Shale, Coal Seam and Tight Gas

Activities in Western Australia’, 2011, pg 4 – 8, 5 at

http://www.DMIRS.wa.gov.au/Documents/Petroleum/PD-SBD-NST-117D.pdf 481 Environment and Communications Legislation Committee inquiry into the Landholders’ Right to Refuse

(Gas and Coal) Bill 2015,(2015) , pg 21 at <

https://www.aph.gov.au/Parliamentary_Business/Committees/Senate/Environment_and_Communications/Gas

_and_Coal/Report> 482 Mr Leslie Manning, Director, p&e law, Proof Committee Hansard, 27 July 2015, pg 38 at <

https://www.aph.gov.au/Parliamentary_Business/Committees/Senate/Environment_and_Communications/Gas

_and_Coal/Report> 483 Mr George Bender, Hopeland Community Sustainability Group, Proof Committee Hansard, 27 July 2015, pg

23 at <

https://www.aph.gov.au/Parliamentary_Business/Committees/Senate/Environment_and_Communications/Gas

_and_Coal/Report>

78

associated petroleum infrastructure is... It could mean anything... To allow them on for $265

was absolutely stupid.’484

Operators in Western Australia and South Australia will face significant risk and challenges

when they seek to enter land to exploit shale and tight gas. Amongst other things, they will

need to negotiate with landholders and others who a right to land. Any land access demands

operators place on communities will likely be opposed. The land access required to exploit

shale and tight gas will lead to significant competition. Having in place appropriate regulatory

regimes to deal with water management is imperative.

2.3.2 Water access and quality protection

In Colorado the media argue that ‘a new race for water is rippling through the drought-scorched

heartland, pitting farmers against oil and gas interests, driven by new drilling techniques that

use powerful streams of water, sand and chemicals to crack the ground and release stores of oil

and gas.485 One industry commentator in the United States insists that as a result of large scale

drilling and chemical injection ‘concerned citizens groups and the media have pointed to

flaming tap water and have worried about chemical contamination; at the same time, industry

representatives and many state regulators have sworn that the practice has never contaminated

groundwater’.486

Most industry commentators argue that the handling and disposal of water is the single greatest

environmental obstacle to shale and tight gas exploitation.487 Most agree that shale and tight

gas exploitation will threaten water resources in some way.488 It is highly likely that Australia

484 Ibid. 485 For Farms in the West, Oil Wells are Thirsty Rivals, Sept 5, 2012 at

http://www.nytimes.com/2012/09/06/us/struggle-for-water-in-colorado-with-rise-in-fracking.html?_r=0 486 Hannah J. Wiseman, ‘Risk and Response in Fracturing Policy’ (2013) 84 University of Colorado Law Review

729, 729 487 World Energy Outlook, Golden Rules for Golden Age of Gas, World Energy Outlook Special Report on

Unconventional Gas, (29 May 2012) pg 32 at

http://www.worldenergyoutlook.org/media/weowebsite/2012/goldenrules/weo2012_goldenrulesreport.pdf 488 Hannah J. Wiseman, ‘Hydraulic Fracturing and Information Forcing’ (2013) 74 Ohio State Law Journal 87-

97

79

will need to focus more on water than the United States given Australia has less surface water

and relies heavily on groundwater.489

Some industry commentators insist that the negative impacts on water resources, if not properly

managed, have the capacity to cause significant environmental and production issues beyond

immediate production areas.490 Those who are strongly opposed to shale and tight gas

exploitation argue that there is a risk to drinking water supplies through contamination.491

Water contamination can result from hydraulic fracturing fluid spills, waste water discharges,

surface water and groundwater contamination by leaking wastewater impoundments;

contamination of groundwater from poorly constructed or maintained wells, and freshwater

depletion.492 Some argue that the risk of groundwater contamination from shale and tight gas

activities, including the use of hydraulic fracturing, is very low.493 However, hydraulic

fracturing can contaminate surface and groundwater through a number of pathways, the main

being spills.494

Water can also be contaminated during earth-moving activities necessary for reclamation —

both interim and final.495 A poorly assembled well can result in contamination due to

inadequate casing or cement failures.496 The potential threat caused by seismic testing can be

significantly diminished or removed by forcing operators to carry out seismic testing a safe

distance from any water wells.497

489 Stephanie Neitzel, P.E. Esq. Principal WaterRich Advisors LLC, Centennial, Colorado, Water quality

regulations for unconventional gas production, United States and Australia comparison, (accessed 12 June

2017) pg 7 at http://www.awa.asn.au/documents/136%20SNeitzel.pdf 490 Ibid. 491 Suzanne Goldenberg, ‘Drinking water contaminated by shale gas boom in Texas and Pennsylvania’ The

Guardian, 16 September 2014 at <https://www.theguardian.com/environment> 492 Katherine E. Konschnik & Mark K. Boling, ‘Shale Gas Development: A Smart Regulation Framework’

(2014) Environmental Science & Technology A 493 Chamber of Mines and Energy South Australia , Submission to the Inquiry into the potential risks and

impacts in the use of hydraulic fracture stimulation (Fracking) to produce gas in the South-East of SA

Submission to Natural Resources Committee, Parliament of South Australia, (2015) pg 7 494 Joel Minor, ‘Local Government Fracking Regulations: A Colorado Case Study’ (2014) 33 Stanford

Environmental Law Journal 61, 71 495 Intermountain Oil and Gas BMP Project, the Colorado Rural Water Association, AirWaterGas and Western

Resource Advocates, Protecting source water in Colorado during oil and gas development, August 2016, pg 1

at http://www.oilandgasbmps.org/docs/CO186_ProtectingSourceWaterAugust2016.pdf 496 Ibid. 497 Ibid.

80

The Natural Resources Committee inquiry into unconventional gas argues that ‘international

and national data demonstrates that, by employing globally leading industry practice, risks of

groundwater contamination can be effectively managed or avoided entirely.’498 According to

Geoscience Australia, the impacts on water from shale gas production are likely to be minimal

apart from where there are more permeable rocks or structures present or where fracturing has

an impact on aquifers.499 They argue that the impact of extracting tight gas is negligible due

to the small amount of water present, except where fracturing impacts on aquifers.500

As far as ACOLA is concerned, the risks to groundwater systems from hydraulic fracturing

well failure is low to moderate, though the doubt about groundwater impacts is high.501 They

argue that there is moderate risk for water impacts related to the reduction in natural surface

water flow (as a result of water abstraction and/or groundwater drawdown).502 Given the shale

and tight gas industry has changed so rapidly, ACOLA insist that this expansion has outpaced

the availability of information for regulators to develop specific regulation.503

While it is possible to pinpoint a range of risks to groundwater and surface water, ACOLA

insist that there is not enough scientific evidence to make claims robust, reliable and easy to

use.504 ACOLA suggest that ‘there is a need to go beyond just identifying risks and start to

acquire quantitative data on frequency and consequence of risks, with a view to developing a

full risk management approach to environmental and related issues, for all shale gas

projects.’505

498 Inquiry into Unconventional Gas (Fracking) in the South East of South Australia, Final Report, One Hundred

Nineteenth Report of the Natural Resources Committee, Tabled in the House of Assembly and ordered to be

published 29 November 2016, p 12 at

https://www.parliament.sa.gov.au/Committees/Pages/Committees.aspx?CTId=5&CId=295 499 Minchin, Dr, S, Unconventional Gas and Water Resources in Australia, Geoscience Australia, (accessed 20

May 2017) pg 3 at http://www.water.anu.edu.au/pdf/2012/newsletter/sminchin.pdf 500 Ibid. 501 ACOLA Secretariat Limited, Shale Gas Development in Australia – Potential impacts and risks to ecological

systems, 11 January 2013 at

http://www.acola.org.au/PDF/SAF06Consultants/Eco%20Logical%20Risk%20and%20Impact%20Jan%20201

3.pdf 502 Ibid. 503 Ibid. 504 Cook, P, Beck, V, Brereton, D, Clark, R, Fisher, B, Kentish, S, Toomey, J and Williams, J (2013). Securing

Australia’s Future – Engineering energy: unconventional gas production,pg 182 at

http://www.acola.org.au/index.php/projects/securing-australia-s-future/project-6 505 Ibid

81

The opposition to shale and tight gas exploitation due to water concerns in many parts of the

United States and Western Europe is outlined succinctly in ‘Water and Shale Gas Development

– Leveraging the US experience in new shale developments’.506 The report insists that given

the industry has changed so rapidly, it has often outpaced the availability of information for

regulators to develop specific guidance.507 The National Water Commission insists that

opportunities exist to improve the management of water in unconventional mining by reducing

regulatory burden and coordinating approaches to regulation.508 A present there is no

consistent approach to managing the use of water in shale and tight gas operations and the

industry (and regulators) in Australia are effectively forced to cherry pick case by case

individual ‘best practice’ mechanisms from an assortment of principles, rules and the laws

designed to regulate the industry.

The Commonwealth’s Office of Water Science commissioned, in 2015, two reports from the

National Centre for Groundwater Research and Training509 on the development of the shale

and tight gas industry in Australia. The first review, largely scientific, related to induced

seismicity, the creation of subsurface pathways, the depletion of shallow aquifers, groundwater

contamination, the disposal of co-produced water (and salt) and surface spills.510 The second

review, legal in nature, provided a summary and comparative analysis of current regulatory

regimes for shale and tight gas production at the state/territory and national levels and identified

the current or potential gaps and proposed a best practice regulatory regime.511 To date, neither

has been publicly released.

The Council of Canadian Academies (CCA) insist that ‘…there is reason to believe that shale

gas development poses a risk to water resources, but the extent of that risk, and whether

substantial damage has already occurred, cannot be assessed because of a lack of scientific data

506 Accenture, ‘Water and Shale Gas Development – Leveraging the US experience in new shale developments’,

2012, 5 at <http://www.accenture.com/SiteCollectionDocuments/PDF/Accenture-Water-And-Shale-Gas-

Development.pdf> 507 Ibid. 508 National Water Commission, Water for mining and unconventional gas under the National Water Initiative, (

accessed 18 June 2016) at http://www.nwc.gov.au/__data/assets/pdf_file/0008/37691/Water-for-mining-and-

unconventional-gas-under-the-National-Water-Initiative.pdf 509 National Centre for Groundwater Research and Training at http://www.groundwater.com.au/ 510 National Centre for Groundwater Research and Training, The Impact of Unconventional Gas on Water

Resources: Replacing Myths with Scientific Evidence, (12 May 2017) at

http://www.petroleum.dmitre.sa.gov.au/__data/assets/pdf_file/0007/230947/Peter_Cook_-

_Impact_of_Unconventional_Gas_on_Water_Resources_-_WG3.pdf 511 Office of Water Science at http://www.groundwater.com.au/news_items/ncgrt-research-highlights

82

and understanding.’512 The CCA insist that there are no proven or verified impacts on

groundwater from shale and tight gas development.513 Western Australia and South Australia

must turn their attention to the regulatory regimes regarding the taking of water, the diversion

of water and the use of water.514

There will be significant risks and challenges linked to shale and tight gas exploitation in

Western Australia and South Australia. Regulatory regimes must be in place to protect water

sources from contamination and operators will only be able to use an amount the community

finds acceptable. Any demands operators place on communities will likely be opposed. The

large volumes required will result in significant competition. Appropriate regulatory regimes

must be in place to deal with water.

2.3.3 Regulation of well technology for drilling and hydraulic fracturing

An estimated 35 000 wells are hydraulically fractured in the United States every year and over

one million have been hydraulically fractured since the first in the late 1940’s.515 ACOLA

have suggested that ‘…based on the United States experience of well spacing, the proportional

extent of fairways (highly prospective zones) and the size of prospective shale gas basins in

Australia, in excess of 200,000 shale gas wells could be drilled’.516

Although the United States has a long history of successfully carrying out hydraulic fracturing

operations, the increase in shale and tight gas exploitation has fuelled various stakeholder

concerns.517 Dr Allan Hawke AC argues that ‘the environmental risks associated with

512 Council of Canadian Academies, Environmental Impacts of Shale Gas Extraction in Canada, The Expert

Panel on Harnessing Science and Technology to Understand the Environmental Impacts of Shale Gas

Extraction, 2014 at

http://www.scienceadvice.ca/uploads/eng/assessments%20and%20publications%20and%20news%20releases/s

hale%20gas/shalegas_fullreporten.pdf 513 Id at 96. 514 Alex Gardner, Nick Duff, Kweku Ainuson & Samuel Manteaw, Regulating Mining Water Use and Impacts

in Ghana: Comparing Australian and Ghanaian Law for Reform Ideas, July 2015, pg 7 515 Water Management Associated with Hydraulic Fracturing, Upstream Segment, API Guidance Document

HF2 First Edition, June 2010, pg vi 516 Frogtech Pty Ltd, Potential Geological Risks Associated with Shale Gas Production in Australia, Melbourne:

Australian Council of Learned Academics, 2013, pg 6 at

<http://www.acola.org.au/PDF/SAF06FINAL/Frogtech_Shale_Gas_Geology_and_Risks%20Jan2013.pdf> 517 Daniel Steinway, ‘Hydraulic Fracturing and the Shale Gas Boom’ (2012) 5 IELR 180-182

83

hydraulic fracturing can be managed effectively subject to the creation of a robust regulatory

regime’.518 A submission to the Standing Committee on Environment and Public Affairs

argued that ‘hydraulic fracturing for unconventional gas in Western Australia is not in the

public interest…is completely unacceptable and should be permanently banned.’519 Another

submitted ‘that WA does not need to proceed down the path of fracking for onshore

unconventional gas…The impacts are serious, the risks severe, the consequences irreversible

and the safe, sustainable alternatives are clear and available’.

One industry observer group, Frogtech, insist that hydraulic fracturing should be ‘prohibited

(or minimised) in areas where users of productive arable land rely, whether now or in the

future’520 and if it must be used that ‘it be extracted from the lowest quality available…land is

rehabilitated to support improved biodiversity condition and ongoing monitoring’.521 Shale

and tight gas production in the United States has exposed, amongst other things, well integrity

concerns.522

The International Energy Agency suggest that rules that deal with well design, construction,

cementing and integrity testing to prevent leaks into aquifers must be accompanied by rigorous

assessments, monitoring and handling of water requirements.523 Some insist that ‘the specific

process of hydraulic fracturing or “fracking” in deep shale, properly managed and regulated, is

unlikely to pose significant risks to groundwater, but other processes associated with

unconventional gas extraction, including mid to long-term well bore integrity, surface spills,

and waste and chemical transport, present risks that need to be properly considered and

managed.’524

518 Allan Hawke AC, Report of the Independent Inquiry into Hydraulic Fracturing in the Northern Territory,

2014, Executive Summary, page x 519 Julian Sharp, Submission, Inquiry into the Implications for W.A. of Hydraulic Fracturing for Unconventional

Gas, 23 August 2013 520 Vic Andrich, Submission, Inquiry into the Implications for W.A. of Hydraulic Fracturing for Unconventional

Gas, 18 September 2013 521 Ibid. 522 Frogtech, Potential Geological Risks Associated with Shale Gas Production in Australia, January 2013, pg 4

at http://www.acola.org.au/PDF/SAF06FINAL/Frogtech_Shale_Gas_Geology_and_Risks%20Jan2013.pdf 523 World Energy Outlook, Golden Rules for Golden Age of Gas, World Energy Outlook Special Report on

Unconventional Gas, (2012) at 17 at

http://www.worldenergyoutlook.org/media/weowebsite/2012/goldenrules/weo2012_goldenrulesreport.pdf 524 Natural Resources Committee, Inquiry into Unconventional Gas (Fracking) in the South East of SA, Final

Report, One Hundred Nineteenth Report of the Natural Resources Committee, Tabled in the House of

Assembly and ordered to be published 29 November 2016, p 12

84

Well integrity comprises pressure and fluid containment during well operations, including

during hydraulic fracturing, the adherence to industry standards and ensuring that fracture fluid

and gas production is confined within the reservoir rock and well bore.525 Wells must be

constructed to prevent gas from migrating into fresh water formations. A properly constructed

well protects drinking water aquifers during shale and tight gas operations.526

Maintaining the integrity of wells is vital to production. A well that is maintained isolates

internal conduits from the surface and subsurface and confines the wells produced fluid to a

production conduit within it.527 Well integrity is the key to protecting underground water

resources528 and has four aspects. Namely, the evaluation of stratigraphic confinement, the

specification of well construction standards, the evaluation of mechanical integrity, and the

monitoring of hydraulic fracturing and the monitoring of producing wells.529

Well design and well integrity are vital to protecting water resources as operators’ drill into

gas-bearing formations. The most important aspect of hydraulic fracturing is well integrity.530

Well integrity protects groundwater from wells’ contents during horizontal drilling and

horizontal fracturing through a combination of steel casing, cement casing and mechanical

isolation devices fitted as a part of the construction process.531

525 Energy Resources Division, Department of the Premier and Cabinet, Gas and Oil in Unconventional

Reservoirs in the South East of South Australia, Version 27/07/17, pg 7 at

https://petroluem.statedevelopment.sa.gov.au 526 Intermountain Oil and Gas BMP Project, the Colorado Rural Water Association, AirWaterGas and Western

Resource Advocates, Protecting source water in Colorado during oil and gas development, August 2016, pg 1

at http://www.oilandgasbmps.org/docs/CO186_ProtectingSourceWaterAugust2016.pdf 527 American Petroleum Institute, Hydraulic Fracturing Operations— Well Construction and Integrity

Guidelines, API guidance document hydraulic fracturing, 1st Edition, October 2009, pg 1 at

http://www.shalegas.energy.gov/resources/HYDRAULIC FRACTURING 1.pdf 528 Crawford School of Public Policy, Unconventional Gas Production and Water Resources, Lessons from the

United States on better governance – a workshop for Australian government officials, 2012, pg 29 at

https://crawford.anu.edu.au/pdf/inthenews/12186-unconventional-gas-document-web-fa.PDF 529 Ibid. 530 Standing Committee on Environment and Public Affairs, Parliament of Western Australia, Implications for

WesternAustralia of Hydraulic Fracturing for Unconventional Gas, November 2015, pg 144 at

http://www.DMIRS.wa.gov.au/Documents/Petroleum/PD-SBD-NST-109D.pdf

http://www.parliament.wa.gov.au/Parliament/commit.nsf/(Report+Lookup+by+Com+ID)/74E61E739E39E57

748257EF9002150FE/$file/ev.fra.151117.rpf.042.xx.pdf 531 American Petroleum Institute, Hydraulic Fracturing Operations— Well Construction and Integrity

Guidelines, API guidance document, hydraulic fracturing, 1st Edition, October 2009, pg 2 at

http://www.shalegas.energy.gov/resources/HYDRAULIC FRACTURING 1.pdf

85

Properly constructed wells minimise the potential of fluids migration into drinking water

aquifers.532 Both horizontal drilling and hydraulic fracturing prevent gas and water from

migrating between different formations penetrated by a wellbore.533 A shale and tight gas well

should be designed to prevent interconnection between gas reservoirs and water aquifers in

order to ensure formation fluids are confined to the well, that there is no leakage and to prevent

substances from being introduced to the well that may cause environmental harm.534

After drilling commences, it stops at various points so that purpose-built steel pipes (casing)

can be fitted.535 The space between the casing and borehole wall is lined with cement that

provides a non-porous barrier preventing cross-contamination between gas bearing formations

and overlying aquifers.536 The wellhead which contains barriers, valves, seals and a gas/water

separator is positioned on the surface to maintain control of the well.537 The wellhead also

incorporates a means of hanging the production tubing and installing the Christmas tree (a

vertical assembly of mechanical elements used in oil exploration and production in surface

and underwater oil and gas wells, primarily for flow control)538 and surface flow-control

facilities in preparation for the production phase of the well.539

532 Mr David Guglielmo, Country Manager, Halliburton Australia Pty Ltd, Transcript of Evidence, 10 February

2014, p 2. 533 Engineering Unit – Wellbore Integrity, COGCC, Department of Natural Resources, (accessed 19 January

2018) at

https://cogcc.state.co.us/documents/about/TF_Summaries/GovTaskForceSummary_Engineering%20Wellbore

%20Integrity.pdf 534 Santos, Drilling and Well Integrity, Technical Fact Sheet, Unconventional Gas Mining, Submission 57 –

Attachment 1, 2016, pg 6 at

http://www.aph.gov.au/Parliamentary_Business/Committees/Senate/Gasmining/Gasmining/Submissions 535 Shale gas in Australia, Drilling and well construction, (accessed 21 June 2017) at http://www.shale-

gas.com.au/industry-operations/drilling-well-construction/ 536 Ibid. 537 Ibid. 538 Investopedia, Christmas tree (oil and gas), (accessed 12 May 2017) at

http://www.investopedia.com/terms/c/christmas-tree-oil-and-gas.asp 539 Wellhead, Schlumberger Oilfield Glossary, (accessed 12 June 2017) at

http://www.glossary.oilfield.slb.com/Terms/w/wellhead.aspx

86

The following diagram shows well casing and cements layers:

Figure 6 Well casing and cement layers540

The conductor casing inhibits loose surface sediment from failing into the well and protects

surface aquifers.541 Conductor casing is roughly 50m deep and placed into the surface hole

and cemented along its full length to ground surface.542 The surface casing protects

groundwater and is set below the potable aquifers where the blowout preventer is installed on

the well.543 This casing is typically set at 800m deep and is cemented to the surface.544 The

intermediate casing isolates unstable whole sections, lost-circulation zones, low-pressure zones

and production zones.545 Intermediate casing is typically used for deeper wells to manage hole

540State of New Mexico, Oil and Gas Well Information, (accessed 12 May 2018) at

http://www.emnrd.state.nm.us/OCD/education.html 541 Department of Mines and Petroleum, Well design and integrity, Petroleum information sheet, 2015, pg 1 at

http://www.DMIRS.wa.gov.au/Documents/Petroleum/PD-SBD-NST-109D.pdf 542 Encana, Wellbore construction, (accessed 18 July 2017) at

https://www.encana.com/sustainability/environment/water/protection/construction.html 543 Department of Mines and Petroleum, Well design and integrity, Petroleum information sheet, 2015, pg 1 at

http://www.DMIRS.wa.gov.au/Documents/Petroleum/PD-SBD-NST-109D.pdf 544 Ibid. 545 PetroWiki, Casing and tubing, (accessed 14 July 2017) at

http://petrowiki.org/Casing_and_tubing#Surface_casing

87

conditions when drilling to a targeted formation.546 The production casing or liner is the last

casing in a well and it runs from total depth to the surface. Liners run from the total depth to a

suitable overlap inside the previous casing.547 Production tubing is fitted inside the casing to

act as a conduit during production.548

In 2011, the Australian Petroleum Production Exploration Association (APPEA) released a

Code of Practice for Hydraulic Fracturing applicable to onshore gas in Western Australia.549

The code was developed by operators based on proven operating principles and leading

practices in other jurisdictions relevant to local conditions. The code supported the public

release of information, subject to the protection that the National Industrial Chemicals

Notification and Assessment Scheme provided for commercially sensitive information.550

The code contains seven guidelines. The aim of guideline one was to guarantee that operators

communicated openly and as early as possible with interested parties.551 This involves

describing risk management strategies to minimise any potential unwanted or adverse

impacts.552 Guideline two was aimed at ensuring that well design and performance practices

include protecting aquifers and groundwater that may be used for commercial or residential

water supply.553

The aim of guideline three was to protect and responsibly use groundwater resources.554 For

example, where appropriate, all water used in hydraulic fracturing operations will be recycled

and/or reused, taking water from aquifers will be subject to Department of Water and

Environment Regulation (DoWER) licence requirements.555 The aim of guideline four is to

reduce the use of chemicals in hydraulic fracturing operations, provide accurate information

546 Department of Mines and Petroleum, Well design and integrity, Petroleum information sheet, 2015, pg 1 at

http://www.DMIRS.wa.gov.au/Documents/Petroleum/PD-SBD-NST-109D.pdf 547 Ibid. 548 Ibid. 549 Australia Petroleum Production Exploration Association, Code of Practice for Hydraulic Fracturing, Western

Australian Onshore Gas, (accessed 18 April 2017) at http://www.newstandard.com.au/wp-

content/uploads/2011/11/APPEA_Code_of_Practice.pdf 550 Ibid. 551 Id at 2. 552 Ibid. 553 Ibid. 554 Id at 3. 555 Ibid.

88

on any chemical use and promote the safe and responsible use of chemicals.556. The aim of

guideline five to ensure that post-fracture stimulation clean-up flowback or produced fluids

cannot come into contact with production aquifers or pollute soil or soil substrate. Guideline

six aims to ensure the fugitive emissions from stimulated wells during flowback and testing

activities are minimised. The aim of guideline seven is to ensure continuous performance

improvement and the sharing of information with regulators and other stakeholders to reduce

potential risks of hydraulic fracturing.557

According to the DMIRS, Western Australia has the most stringent well integrity and resource

management conditions in Australia following the introduction of new regulations for shale

and tight gas.558 DMIRS believe the state is well placed to learn from experiences in other

jurisdictions and to adopt international best practice standards to further strengthen their robust

regulatory system ensuring the environment and communities are protected as this new

industry is developed.559 The Natural Resources Committee found that while hydraulic

fracturing was unlikely to pose significant risks to groundwater, other processes, including mid

to long-term well integrity, surface spills and waste and chemical transport, presented risks that

needed to be properly considered.560

2.3.4 Decommissioning and associated issues

The DMIRS consider ‘decommissioning’ to mean ‘take out of service’ and note that it is not

generally defined in legislation.561 The DMIRS insist that ‘this may be a contributing factor to

its confusion with terms such as ‘removal’ and ‘disposal’, which are two possible processes

applied in decommissioning, and sometimes also with ‘abandonment’.562

556 Ibid. 557 Id at 4. 558 Department of Mines, Industry Regulation and Safety, New Resource Management Regulations, 1 July 2015

at http://www.DMIRS.wa.gov.au/7105_21668.aspx 559 Department of Mines, Industry Regulation and Safety, New Resource Management Regulations, 1 July 2015

at http://www.DMIRS.wa.gov.au/7105_21668.aspx 560 Natural Resources Committee, Inquiry into Unconventional Gas (Fracking) in the South East of South

Australia, Final Report, One Hundred Nineteenth Report of the Natural Resources Committee, Tabled in the

House of Assembly and ordered to be published 29 November 2016, p 12 at

https://www.parliament.sa.gov.au/Committees/Pages/Committees.aspx?CTId=5&CId=341 561 Department of Mines, Industry Regulation and Safety, Government of Western Australia, Petroleum

Decommissioning Guideline, 30 October 2017 , pg 2 at www.dmirs.wa.gov.au 562 Ibid.

89

The DMIRS define ‘decommissioning as the controlled process of retiring a petroleum

operation from service in a manner that is safe and environmentally responsible, followed by

regulated removal of property from the licence or permit area, and the rehabilitation of the

environment to the approved state.’563 The process can also comprise ‘the partial or progressive

removal of facilities from a field as conditions change, or offtake rates decline and the ultimate

cessation of production is foreshadowed.’564

The practice of safely decommissioning a well, dismantling facilities and rehabilitating

land to its natural state or some other form desired by society has been common practice

in the petroleum industry for many decades and the industry has developed state-of-the-

art skills in performing this function.565

It is estimated that around 2.6 million gas wells have been drilled in the United States since

1949.566 Two decades ago, there were about 1.2 million abandoned oil and gas wells in the

United States, 200 000 of them unplugged.567 Many states in the United States have found it

difficult to plug wells at the rate at which they are abandoned.568 The state of New York

plugged 25 percent of its abandoned wells in 2010, down from 27 percent in 1994.569 Texas

563 Ibid. 564 Ibid. 565 Parliamentary Inquiry into the Implications for Western Australia of Hydraulic Fracturing for

Unconventional Gas, Submission for the Chamber of Minerals and Energy Western Australia, September

2013, pg 38 at

http://www.parliament.wa.gov.au/Parliament/commit.nsf/(Evidence+Lookup+by+Com+ID)/99D8D0023E339

C6F48257C4000110456/$file/ev.fra.131004.sub.112.the+chamber+of+minerals+and+energy+of+western+aus

tralia.pdf 566 US Energy Information Administration, Crude Oil and Natural Gas Exploratory and Development Wells,

(accessed 18 July 2017) at http://www.eia.gov/dnav/ng/ng_enr_wellend_s1_m.htm 567 EPA, Management of Wastes from the Exploration, Development, and Production of Crude Oil, Natural Gas,

and Geothermal Energy. Office of Solid Waste and Emergency Response, Washington, D.C, 1987 at <

https://nepis.epa.gov/Exe/ZyNET.exe/20012D4P.TXT?ZyActionD=ZyDocument&Client=EPA&Index=1986+

Thru+1990&Docs=&Query=&Time=&EndTime=&SearchMethod=1&TocRestrict=n&Toc=&TocEntry=&QF

ield=&QFieldYear=&QFieldMonth=&QFieldDay=&IntQFieldOp=0&ExtQFieldOp=0&XmlQuery=&File=D

%3A%5Czyfiles%5CIndex%20Data%5C86thru90%5CTxt%5C00000015%5C20012D4P.txt&User=ANONY

MOUS&Password=anonymous&SortMethod=h%7C-

&MaximumDocuments=1&FuzzyDegree=0&ImageQuality=r75g8/r75g8/x150y150g16/i425&Display=hpfr&

DefSeekPage=x&SearchBack=ZyActionL&Back=ZyActionS&BackDesc=Results%20page&MaximumPages

=1&ZyEntry=1&SeekPage=x&ZyPURL> 568 RJ Davies et al, ‘Oil and gas wells and their integrity: Implications for shale and unconventional resource

exploitation’ (2014) Marine and Petroleum Geology 9 569 Ibid.

90

has an ‘aggressive program’ for plugging abandoned wells and plugged more than 41 000

between 1991 and 2009 as part of its well plugging program.570

Decommissioning is becoming a rapidly developing industry particularly worldwide.571 Given

Western Australia’s level of well immaturity and numbers, none have reached their economic

limit and ceased production, though more fields are now being identified and preparing for

decommissioning.572

All wells will eventually become unproductive and should be plugged.573 Plugging and

abandoning has not changed substantially over the past 100 years and while there have been

improvements in the quality of the materials used and changes to the methods employed to

plug wells, there have not been specific variations that have elevated the technology of

plugging wells.574 Plugging and abandoning wells that are no longer viable, or have wellbore

issues and require closure, has traditionally been conducted as an afterthought.575

A recent analysis of Colorado’s 98 223 wells revealed that 45 007 were suitable for final

reclamation, meaning that they had been plugged and abandoned, drilled and abandoned

without production (i.e., dry and abandoned wells) or permitted but never drilled (i.e.,

abandoned locations).576 Of the 45 007 wells, 26 322 (58 percent) passed a final reclamation

inspection and were considered closed with the remaining 18 685 in different stages of

reclamation and awaiting final inspection.577

570 Ibid. 571 Department of Mines, Industry Regulation and Safety, Government of Western Australia, Petroleum

Decommissioning Guideline, 30 October 2017 , pg 2 at www.dmirs.wa.gov.au 572 Ibid. 573 Plugging and abandonment of oil and gas wells, prepared by the Technology Subgroup of the Operations &

Environment Task Group, Paper #2-25, Working Document of the NPC North American Resource

Development Study, 15 September 2011, pg 117 574 Id at 19. 575 Id at 6. 576 Colorado Oil and Gas Conservation Commission, Department of Natural Resources, Final Reclamation

Inspection and Implementation Program: A Status Report to the Commission, December 2015, pg 2 at

https://cogcc.state.co.us/Announcements/Final_Reclamation_Report_20151208.PDF 577Ibid.

91

Decommissioning is one of the final stages in a wells’ service life.578 Decommissioning is

undertaken to isolate and protect fresh water and gas bearing zones, to prevent leaks from or

into wells and involves removing surface structures in order to rehabilitate land.579 The term

decommissioning is used interchangeably with ‘plug and abandon’ and ‘abandonment’ and

involves preparing wells for permanent closure.580 Abandoned, idle and orphaned denotes

wells where an operator has failed to locate commercial quantities of gas; wells have become

unproductive or are ‘without an owner’.

An orphaned well is deemed abandoned when an operator chooses not to claim responsibility

for it or where an owner cannot be found.581 For example, if an operator goes bankrupt or a

well becomes orphaned in Wyoming, the state becomes responsible for future

management.582 Broadly speaking, well abandonment involves an operator cementing and

capping a well to minimise the threat it may pose to, amongst other things, water resources.583

An uncapped or incorrectly sealed well can adversely impact public health, safety and the

quality of groundwater resources in the vicinity.584 Plugging ensures that gas, water, and other

substances that facilitate extraction are quarantined to their original reservoir.585

Decommissioning inhibits spills, water contamination, and the release of dangerous gas.586 The

isolation of permeable gas bearing formations protects underground resources, prevents

578 Department of Environmental Protection, Pennsylvania, Well abandonment procedures, Chapter 7, (accessed

19 June 2017) at

https://www.dep.state.pa.us/dep/deputate/watermgt/Wc/Subjects/SrceProt/ground/sympos/GrdMonitor-

chap7.htm 579 Department of Mines and Petroleum, Government of Western Australia, Closure and decommissioning,

(accessed 19 May 2017) at http://www.DMIRS.wa.gov.au/Petroleum/Closure-and-decommissioning-

8667.aspx 580 Standing Committee on Environment and Public Affairs, Parliament of Western Australia, Report 42,

Implications for Western Australia of Hydraulic Fracturing for Unconventional Gas, November 2015, pg 151 at

http://www.parliament.wa.gov.au/Parliament/commit.nsf/(Report+Lookup+by+Com+ID)/74E61E739E39E5774

8257EF9002150FE/$file/ev.fra.151117.rpf.042.xx.pdf 581 Id at 5. 582 Stephanie Joyce, Wyoming Public Radio & Jordan Wirfs-Brock, The Rising Cost of Cleaning Up After Oil

and Gas, [DATE OR DATE VIEWED?] at http://insideenergy.org/2015/10/01/the-rising-cost-of-cleaning-up-

after-oil-and-gas/ 583 P Cook, V Beck, D Brereton, R Clark, B Fisher, S Kentish, J Toomey & J Williams, Engineering Energy:

Unconventional Gas Production, Report for the Australian Council of Learned Academies, May 2013, p 176 584 Department of Environmental Protection, Pennsylvania, Well abandonment procedures, Chapter 7, (accessed

13 June 2017) at

https://www.dep.state.pa.us/dep/deputate/watermgt/Wc/Subjects/SrceProt/ground/sympos/GrdMonitor-

chap7.htm 585 Rule 319(a)(1) of the COGCC rules 586 Stan Olmstead, Report of oil & gas well abandonment and reclamation on federal lands administered by

BLM-Utah, 2015, pg 1 at http://www.peer.org/assets/docs/blm/3_30_15_Utah_well_report.pdf

92

potential contamination of potable water sources and prevents surface leakage.587 Plugging

encompasses sealing the wellbore at various depths to avoid possible contamination of aquifers

or formations outside the producing formation.588

In order to decommission a well, the production zone is insulated with a cement plug589 and

barriers are placed within the well casing to ensure no fluids can enter or exit the well once the

wellhead is disconnected.590 Although cement is predominantly used to seal wells, drilling

mud, bentonite, and mechanical plugs also are used in conjunction with cement.591 Given

fracking depends on cement to guarantee well integrity, and isolation from aquifers, great care

must be taken to ensure a perfect seal that lasts long after a well ceases production.592

An operator who abandons a well must restore the natural integrity of the formation that was

pierced by the wellbore.593 A well that is incorrectly abandoned provides a pathway for brines,

gas or other fluids to migrate up the well and into shallow drinking water aquifers or to the

surface.594 An abandoned well usually contains a surface casing that extends to depths below

a drinking water aquifer, and a (set of) production string(s) running to the target formation.595

587 Global CCS Institute, Well plugging and abandonment techniques, (accessed 18 October 2017) at

https://hub.globalccsinstitute.com/publications/long-term-integrity-co2-storage-%E2%80%93-well-

abandonment/2-well-plugging-and-abandonment 588 Colorado State University, Oil and Gas Development in Colorado, Extension, Consumer Series, Fact Sheet

No. 10. 639, (accessed 12 May 2017), pg 5 at http://extension.colostate.edu/docs/pubs/consumer/10639.pdf 589 Department of Mines, Industry Regulation and Safety, Guide to the Regulatory Framework, Shale and Tight

Gas in WA, A Whole of Government Approach, 2015 Edition, pg 31 at

http://www.DMIRS.wa.gov.au/Documents/Petroleum/WEB_Shale_and_Tight_Gas_Framework.pdf 590 Id at 21. 591 Above, note 574. 592 Standing Committee on Environment and Public Affairs, Parliament of Western Australia, Implications for

Western Australia of Hydraulic Fracturing for Unconventional Gas, Submission 43 from Sven Borg, 18

September 2013, p 16 593 Global CCS Institute, Well plugging and abandonment techniques, (accessed 18 October 2017) at

https://hub.globalccsinstitute.com/publications/long-term-integrity-co2-storage-%E2%80%93-well-

abandonment/2-well-plugging-and-abandonment 594 Ibid. 595 Ibid.

93

The term ‘rehabilitation’ is used interchangeably with ‘reclamation’.596 Land is considered

rehabilitated when it is returned to its prior condition.597 There are a various number of

different motivations for returning non-productive well sites and associated land to pre-

operation conditions i.e. environmental and multiple use concerns.598 Decommissioning is

becoming increasingly more important as a result of the high costs involved which impact on

the fiscal limits and the life of a field.599

2.4 Conclusion

Shale and tight gas has emerged as a significant energy source for those countries willing and

able to exploit it. In most countries, this willingness is meet with apprehension, particularly in

relation to land access, water access and quality protection, the regulation of wells for hydraulic

fracturing and decommissioning and associated issues. The aim of the chapter was to provide

context to the regulatory review.

This chapter provided the context for the comparative regulatory analysis that will be

undertaken in Chapter 4. It defined shale and tight gas and examined the production stages and

production methods required to exploit shale and tight gas i.e. horizontal drilling and hydraulic

fracturing, the footprint of shale and tight gas operations and he impact on ground and surface

water. This chapter defined resource classifications, summarised Australia’s shale and tight

gas prospectivity and examined the role of water, volume required and availability in Australia.

The chapter encompassed a literature review that focused on the community concerns with

shale and tight exploitation and the key regulatory issues. There is no consistent approach to

regulating the exploitation of shale and tight gas. The knowledge gaps are significant and likely

the result of Western Australia and South Australia disregarding what has happened in the

596 Standing Committee on Environment and Public Affairs, Parliament of Western Australia, Report 42,

Implications for Western Australia of Hydraulic Fracturing for Unconventional Gas, November 2015, pg 150

at

http://www.parliament.wa.gov.au/Parliament/commit.nsf/(Report+Lookup+by+Com+ID)/74E61E739E39E57

748257EF9002150FE/$file/ev.fra.151117.rpf.042.xx.pdf 597 Ibid. 598 Stan Olmstead, Report of oil & gas well abandonment and reclamation on federal lands administered by

BLM-Utah, 2015, pg 1 at http://www.peer.org/assets/docs/blm/3_30_15_Utah_well_report.pdf 599 Department of Mines, Industry Regulation and Safety, Government of Western Australia, Petroleum

Decommissioning Guideline, 30 October 2017, pg 2 at www.dmirs.wa.gov.au

94

United States when developing their regulatory regimes. This thesis distinguishes itself from

the existing Australian literature by presenting a comparative analysis which focuses on land

access, water use, drilling, hydraulic fracturing, decommissioning and rehabilitation in Western

Australia, South Australia and Colorado. Much of the focus in Australia to date has been on

coal seam gas exploitation and mining.600 The lack of attention given to the exploitation of

shale and tight gas is a primary reason for the need for a regulatory review at this time. Prior

to the emergence of the coal seam gas industry on the east coast of Australia, the interaction of

petroleum legislation with water resources legislation, and water impacts generally caused less

concern than the water impacts from mining.

Western Australia, South Australia and Colorado all have diverse regimes to manage shale and

tight gas exploitation. While regulatory diversity by itself is not a significant problem (and not

overly surprising) the question of whether it is appropriate when it comes to regulating certain

aspects of exploitation depends largely on whether it is embedded in underlying differences.601

There are certain aspects of regulation that should not be treated differently simply because

exploitation is occurring in another jurisdiction.

The way in which jurisdictions regulate the exploration, production and abandonment of shale

and tight gas is clearly more heterogenous than homogenous.602 The ‘heterogeneity of shale

gas regulations is pervasive; it can be seen in what states regulate and how stringently they do

so’.603 The absence of a national framework similar to the one for coal seam gas604 reinforces

the view that Australia has a ‘wait and see’ approach when it comes to a regulatory regime for

shale and tight gas.

Notwithstanding this heterogeneity in shale gas regulation, and the lack of an Australian

national consensus on a regulatory regime for shale gas, there is value in undertaking a

comparative analysis of the three respective regimes. This chapter has identified four key issues

600 Ibid. 601 Nathan Richardson, Madeline Gottlieb, Alan Krupnick& Hannah Wiseman, The State of State Shale Gas

Regulation, Executive Summary, May 2013, pg 5 602 Simon Robb, A Best Practice Regulatory Proposal for Shale Gas Production, The University of Western

Australia, 2014, pg 84 603 Nathan Richardson, Madeline Gottlieb, Alan Krupnick & Hannah Wiseman, The State of State Shale Gas

Regulation, Executive Summary, May 2013, pg 5 604 The National Harmonised Regulatory Framework for Natural Gas from Coal Seams 2013, Standing Council

on Energy and Resources at http://www.scer.gov.au

95

of regulatory attention that have generated significant community concern in all three

jurisdictions being studied: land access, water access and quality protection, well technology

for drilling and fracking, and decommissioning and rehabilitation of associated land uses.

These issues are the subject of the comparative regulatory review in Chapter 4.

The next chapter provides a brief history of mineral and petroleum ownership which includes

an examination of indigenous rights. The chapter also examines regulatory approvals

focusing on environmental approvals and assessment. Chapter 3 also examines the various

regulatory approaches that can be used to manage the exploitation of shale and tight gas.

96

3 TENURE, APPROVALS AND REGULATORY APPROACHES

3.1 Introduction

Australia’s mineral and petroleum resources within three nautical miles offshore are held by

the Crown in the right of the States and Territories. The State and Territory Parliaments have

passed laws to manage land allocation (which typically withholds mineral and petroleum rights

to the Crown), and to allocate those mineral and petroleum exploration and production rights

separately from land title.605 The minerals and petroleum legislation also provides for the rights

holders to gain access to and over the surface of the land (held by others) in order to exercise

their rights.

Being able to access and use land is essential for the development of commerce, including

agriculture, manufacturing, mining, and shale and tight gas.606 The Commonwealth

Parliament’s Environment and Communications Legislation Committee inquired into land

access and unconventional gas exploitation, arguing that ‘the tension that can exist between

landholders and resource companies is a consequence of Australia’s system of mineral

rights’.607 Many land owners mistakenly believe that they enjoy an absolute right to determine

precisely who may enter or remain on their land, and may exclude any persons from trespassing

on that land.608

This chapter examines land and mineral and petroleum rights in Western Australia, South

Australia and Colorado. It will do this by examining the various tenure regimes in terms of

resource ownership, the petroleum entitlement system, regulatory approvals and environmental

assessment. The chapter will also examine the regulatory approaches each jurisdiction uses to

605 Department of Industry, Innovation and Science, Unconventional Gas, (accessed 28 May 2017) at

https://industry.gov.au/resource/UpstreamPetroleum/Pages/UnconventionalGas.aspx 606 Department of Mines, Industry Regulation and Safety, Land use and access, (accessed 18 June 2017) at

http://www.dmp.wa.gov.au/Petroleum/Land-use-and-access-20009.aspx 607 Environment and Communications Legislation Committee inquiry into the Landholders’ Right to Refuse

(Gas and Coal) Bill 2015, (5 March 2015), pg 16 at

https://www.aph.gov.au/Parliamentary_Business/Committees/Senate/Environment_and_Communications/Gas

_and_Coal 608 Tina Hunter, Land Access on Private Land for Mineral and Petroleum Activities, A review of existing

provisions in Australian states and Territories and selected overseas jurisdictions, February 2017, pg 8

97

manage the exploitation of shale and tight gas. This includes the risk based approach, objective

based approach, command and control and case by case permitting.

3.2 Mineral and petroleum ownership

The Crown in the right of the States and Territories owns mineral and petroleum resources in

their natural locations. The public ownership of minerals is common to most former British

colonies and has been and is an important source authority to approve and regulate resource

exploitation in return for payment of public royalty revenue. The exploitation of mineral and

petroleum resources is generally undertaken by private commercial resources companies or

joint ventures under authority from the state or territory governments on condition of payments

of royalties.

There are two common forms of interests in land: crown leasehold interest609 and freehold

(private ownership) interest.610 Crown leasehold land is land that is leased to a person or

company by the state (as the Crown).611 There are different forms of leasehold tenure - two

thirds of Crown-owned land in northern Australia is under pastoral leasehold.612 Freehold land

offers the most complete form of land ownership (in perpetuity) and it allows land holders to

deal with the land including selling, leasing, licensing or mortgaging the land, subject to

compliance with applicable laws such as planning and environment laws.613

The ownership of everything linked with land is not absolute, as the States, Territories and

Commonwealth can withhold certain rights, such as the right to use minerals or petroleum.614

As pointed out by one industry commentator:

609 Austrade, Leasehold land, What does title mean? , (accessed 15 April 2018) at <

https://www.austrade.gov.au/land-tenure/land-tenure/leasehold-land> 610 Austrade, Freehold land, What does title mean?, (accessed 15 April 2018) at <

https://www.austrade.gov.au/land-tenure/land-tenure/freehold-land> 611 Austrade, Leasehold land, What does title mean?, (accessed 15 April 2018) at <

https://www.austrade.gov.au/land-tenure/land-tenure/leasehold-land> 612 Ibid. 613 Austrade, Freehold land, What does title mean?, (accessed 15 Aprill 2018) at <

https://www.austrade.gov.au/land-tenure/land-tenure/freehold-land> 614 Ibid.

98

The common law scope of private land ownership has been modified by legislation

enacted in each state and territory which purports to vest the ownership of minerals and

resources back to the state. Indeed, all Australian states and the Northern Territory

have legislatively declared that petroleum in situ is owned, without exception, by the

Crown regardless of when the land containing the petroleum passed into private

ownership.615

Australia’s common law position was altered by state and territory mining and petroleum

legislation.616 The outcome has been a rejection of the notion of private ownership of minerals

based on land ownership and, instead, the adoption of a policy of statutorily reserving all

minerals and petroleum from future Crown grants of land.617 There are, however, a small

number of operational mining leases in Western Australia granted before 1899 that provide for

private ownership of minerals except for the ‘royal metals of gold and silver’.618

The PGERA states that, ‘petroleum, geothermal energy resources and geothermal energy on or

below the surface of all land within this State, whether alienated in fee simple or not so

alienated from the Crown, are and shall be deemed always to have been the property of the

Crown’.619 The exploration and production of shale and tight gas in Western Australia is

principally the responsibility of the State Minister for Mines and Petroleum through the

DMIRS. The discovery and development is carried out by the private sector in line with a

system of access rights to resources which assists operators and provides long term community

benefits. Similarly, in South Australia, ‘property in petroleum and other regulated resources

is vested (or continues to be vested) in the Crown...on the production of petroleum, or some

other regulated substance, by a person lawfully entitled to produce the petroleum or other

regulated substance, it becomes the property of the person who produced it.’620

615 Environment and Communications Legislation Committee inquiry into the Landholders’ Right to Refuse

(Gas and Coal) Bill 2015, (2015), Professor Samantha Hepburn, Submission 86, p 2 616 Tina Hunter, Land Access on Private Land for Mineral and Petroleum Activities, A review of existing

provisions in Australian states and Territories and selected overseas jurisdictions, February 2017, pg 8 617 Department of Mines, Industry Regulation and Safety, Private Land Provisions, (accessed 2 January 2018) at

< http://www.DMIRS.wa.gov.au/Documents/Minerals/Minerals-Information-brochures-

private_land_provisions-4.pdf> 618 Industry Commission, Mining and Minerals, Processing in Australia, Volume 3: Issues in Detail, Report

No.7, 25 February 1991, Ownership of Minerals, Australian Government Publishing Service Canberra, pg 7 619 Petroleum and Geothermal Energy Act 2000, s 9 620 Petroleum and Geothermal Energy Act 2000, s 5

99

By comparison, land and minerals in the United States are subject to a private ownership

framework, unless they are located in federal public lands.621 The federal government owns

thirty per cent of total lands and a large amount of natural gas deposits lies below federal

lands.622 The federal government retains and manages, through federal agencies, most of the

land suitable for shale and tight gas exploitation. The Bureau of Land Management (BLM)

and the United States Forest Service (USFS), federal agencies, also have a role in regulating

shale gas and hydraulic fracturing.

The BLM and USFS provide guidelines which all operations that have been approved under a

federal oil and gas lease must follow.623 The BLM leases minerals and administers oil and gas

development activities on over 570 million acres.624 A further 56 million acres of split estates

also exist; where private individuals own surface rights and the federal government owns

subsurface rights.625 The BLM leases federal minerals and administers oil and gas leases, in

cooperation with other federal agencies or private surface owners where appropriate.626 The

BLM manages public lands, including the federal mineral estate under a mandate of multiple

use as set out in the Federal Land Policy and Management Act of 1976627 and issues

competitive and non-competitive leases.628

Outside Federal public lands, a surface landowner’s claim to mineral or petroleum title rests at

common law on the cujus est solum doctrine; that is, whoever owns the soil owns the air above

and down to the depths.629 Some commentators insist that the United States position is ‘largely

621 Samantha Hepburn, ‘Does Unconventional Gas Require Unconventional Ownership? An Analysis of the

Functionality of Ownership Frameworks for Unconventional Gas Development’ (2013) 8:1 Journal of

Environmental and Public Health Law 1 622 Stephanie Neitzel, P.E. Esq, Water Quality Regulations for Unconventional Gas Production United States

and Australia Comparison, WaterRich Advisors LLC, at <

http://www.awa.asn.au/documents/136%20SNeitzel.pdf> (assessed 20 July 2017) 623 DOI & USDA, Surface Operating Standards and Guidelines for Oil and Gas Exploration and Development:

The Gold Book, 2007 at

http://blm.gov/pgdata/etc/medialib/blm/wo/MINERALS_REALTY_AND_RESOURCE_PROTECTION_/ene

rgy/oil_and_gas.Par.18714.File.dat?OILgas.pdf 624 Bureau of Land Management, (accessed 13 March 2017) at www.blm.gov 625 Ibid. 626 Ibid. 627 The Federal Land Policy and Management Act of 1976 (United States) at

http://www.blm.gov/flpma/FLPMA.pdf 628 [AUTHOR?], What is BLM’s authority for leasing oil and gas?, (accessed 18 May 2017) at

http://www.blm.gov/wo/st/en/prog/energy/oil_and_gas/questions_and_answers.html 629 Bradbrook, A.J, ‘The Relevance of the Cujus est Solum Doctrine to the Surface Landowner’s Claims to

Natural resources located above and beneath his Land’ (1998) 11 Adelaide Law Review 462, 468

100

a historical accident’.630 A key principle of the United States land classification system lies in

the power of a surface estate owner to sever or ‘split’ the mineral estate from the surface

estate.631 In the United States, the mineral estate prevails over the surface estate.632

A split estate occurs when the ‘surface estate and all or part of the mineral estate in a particular

parcel are not owned by the same party’.633 For example, split estate rules apply when the

surface is privately held and minerals are publicly held. It also applies where the surface is

private and the minerals are private, or where the surface is public and the minerals are private.

In Colorado’s DJ/Wattenberg Basin, the resources and mineral estate are not publicly held but

owned by private entities such as individuals or corporations. In Western Colorado, there is

public ownership of minerals and resources.

3.3 Grant of a petroleum resource tenure

3.3.1 Western Australia

In Western Australia, a petroleum operation means ‘an operation to explore for petroleum…an

operation to drill for petroleum…an operation to recover petroleum…the injection of

petroleum [and] any other kind of operation that is prescribed by the regulations not to be a

petroleum operation for the purposes of this definition.’634

Before operators carry out exploration activities, they must obtain an exploration permit635 or

drilling reservation.636 An operator must submit an application to DMIRS for approval that is

630 Kendor P. Jones, John F. (Jeff) Wellborn, Chelsey J. Russell ‘Split Estates and Surface Access Issues’

Landman’s Legal Handbook, Chapter 9 (Ricky Mt Min. L. Fdn., 5th ed, 2013) 631 Samantha Hepburn, ‘Does Unconventional Gas Require Unconventional Ownership? An Analysis of the

Functionality of Ownership Frameworks for Unconventional Gas Development’ (2013) 8:1 Journal of

Environmental and Public Health Law 22 632 Catherine Toan, Esq, Split Estates, Colorado Environmental Law Ltd, (accessed 16 June 2017) at

http://www.oilandgasbmps.org/docs/GEN324_split%20estates.pdf 633 Kendor P. Jones, John F. (Jeff) Wellborn, Chelsey J. Russell ‘Split Estates and Surface Access Issues’

Landman’s Legal Handbook, Chapter 9 (Ricky Mt Min. L. Fdn., 5th ed, 2013)

pg 181 634 Petroleum and Geothermal Energy Resources Act 1967 (WA), s 5 635 Petroleum and Geothermal Energy Resources Act 1967 (WA), s 31 636 Ibid s 29(1)

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accompanied by work and expenditure proposals, a summary of the technical qualifications of

the applicant (and their employees) and the technical advice and financial resources at their

disposal.637 Operators often carry out exploration activities as a result of acreage releases or

under a special prospecting authority.638 Acreage releases are usually made once or twice a

year and are usually announced at industry events.639 DMIRS releases prospectivity reports

for the release areas, data for each release area, application process information, assessment

criteria, land access information (native title and environment) and other relevant

information.640

A special prospecting authority title allows an operator to carry out surveys on the physical or

chemical properties of the rocks in the area for a period of six months, but does not allow them

to drill wells.641 If a discovery is not considered economically sustainable, an operator may

obtain a retention lease642 so that if it becomes viable in the future it can be converted to a

production licence.643

3.3.2 South Australia

All exploration, production and abandonment activities in South Australia are administered by

the Department of Premier and Cabinet (DPC) which is the lead regulatory agency in

accordance with the PGEA and various other Acts. In South Australia, , ‘regulated activity’

comprises ‘…exploration for petroleum or another regulated resource; or operations to

establish the nature and extent of a discovery of petroleum or another regulated resource, and

to establish the commercial feasibility of production and the appropriate production techniques;

or production of petroleum or another regulated substance.’644

637 Ibid s 31(1)(d)(i) to (iv)). 638 Petroleum and Geothermal Energy Resources Act 1967 (WA), s 105 639 Department of Mines, Industry Regulation and Safety, Introduction to petroleum acreage, (accessed 5 May

2018) at http://www.dmp.wa.gov.au/Petroleum/Petroleum-acreage-introduction-1585.aspx 640 Ibid. 641 Petroleum and Geothermal Energy Resources Act 1967 (WA), s 105 642 Petroleum and Geothermal and Energy Resources Act 1967 (WA), s 48A 643 Petroleun and Geothermal Energy Resources Act 1967 (WA), s 49 644 Petroleum and Geothermal Energy Act 2000 (SA), s 10

102

An exploration licence authorises an operator to carry out exploration for regulated

resources.645 An exploration licence application must include a proposed work program which

includes the cost of operations to be carried out under the program in each year of the licence,

a technical report that assesses the prospectivity of the area, and how the proposed work

program relates to this prospectivity.646 Regard must be given to the suitability of an operator’s

work program in evaluating prospectivity and discovery of regulated resources, the adequacy

of their technical and financial resources and the stated criteria for evaluation of the

applications.647 An operator who holds an exploration licence is entitled to the grant of a

corresponding retention licence or production licence for a regulated resource discovered in

the licence area.648

3.3.3 Colorado

Shale and tight gas development on non-federal land is regulated under the OGCA and COGCC

rules. The Colorado Oil and Gas Conservation Commission (COGGC) promotes the

exploration, development and conservation of Colorado’s oil and gas resources and also

handles the drilling permit process and ensures operators comply with state based statutes and

regulations. Operators must submit several forms to the COGCC before commencing shale

and tight gas operations.649 They must file a Registration for Oil and Gas Operations

(Form 1)650, apply for a Permit to Drill (Form 2) 651 and submit an Oil and Gas Location

Assessment (Form 2A) prior to disturbing ground linked to new operations. 652 The permit to

drill application must specify the distance between the well and wall or corner of the nearest

building, public road, above ground utility, railroad, and property line, include a wellbore

diagram, well location plat (the plat shall be a current scaled drawing(s) of the entire section(s)

645 Petroleum and Geothermal Energy Act 2000 (SA), s 21(2) 646 Petroleum and Geothermal Energy Regulations 2013 (SA), r 6 647 Petroleum and Geothermal Energy Act 2000 (SA), s 23 648 Ibid s 21(3) 649 Code of Regulations 2 CCR 404-1 at

https://www.sos.state.co.us/CCR/GenerateRulePdf.do?ruleVersionId=6271&fileName=2%20CCR%20404-1 650 Rule 302 of COGGC rules at< https://cogcc.state.co.us/documents/reg/Rules/LATEST/CompleteRules.pdf> 651 Rule 303 of COGGC rules at < https://cogcc.state.co.us/documents/reg/Rules/LATEST/CompleteRules.pdf 652 Form 2A of the COGCC rules at

https://cogcc.state.co.us/documents/reg/Forms/PDF_Forms/Form2A_20130806.pdf

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penetrated by the proposed well with the following minimum information) and deviated

drilling plan.653

An operator can enter into a voluntary comprehensive drilling plan (CDP).654 CDP’s identify

foreseeable gas activities, facilitate discussion about potential impacts and identify measures

to minimise adverse impacts to the environment.655 An operator may ask the Colorado

Department of Public Health and Environment and surface owners to participate in compiling

a CDP.656 The COGCC rules contain a number of incentives to encourage operators to develop

CDP’s.657 For example, if the CDP contains information similar to what is contained in an oil

and gas assessment and the CDP has been subject to the same processes an oil and gas,

assessment is not be required.658

3.4 Indigenous land and related interests

At various times, operators in Australia have raised concerns about the land access negotiation

process, specifically, that when land is subject to a native title claim they feel negotiations can

be lengthy and complex and can consist of multiple parties, which in turn can lead to significant

delays.659 In the United States, some industry observers insist that the ‘complex history

between the federal government and American Indian tribes has created an equally complex

division of authority between federal and tribal governments regarding oil and gas development

on tribal lands’.660 In the United States, the ownership of minerals and the affected surface

lands is vital in order to determine which regulations apply during a gas operation.661

653 Id at rule 303. 654 COGCC rules and regulations, definitions (100 Series), Comprehensive Drilling Plan, 100-2 655 Rule 216(a) of the COGCC rules at <

https://cogcc.state.co.us/documents/reg/Rules/LATEST/CompleteRules.pdf 656 Rule 216.d.(2) of the COGCC rules at <

https://cogcc.state.co.us/documents/reg/Rules/LATEST/CompleteRules.pdf 657 Rule 216.f. of the COGCC rules at <

https://cogcc.state.co.us/documents/reg/Rules/LATEST/CompleteRules.pdf 658 Rule 216.f.(1) of the COGCC rules at <

https://cogcc.state.co.us/documents/reg/Rules/LATEST/CompleteRules.pdf 659 Minerals and Energy Resource Exploration, Productivity Commission Inquiry Report, No 65, 27 September

2013, p 127 660 University of Colorado at Boulder, Intermountain Oil and Gas BMP Project, Indian Lands, (accessed 18 June

2017) at < http://www.oilandgasbmps.org/laws/tribal/> 661 Ibid.

104

Australia’s native title regime and the Indian tribes’ regime in the United States add another

complex layer to an operator’s quest to exploit shale and tight gas. Australia’s native title

regime enables Indigenous communities to claim their native title rights and interests in the

land through the Native Title Act 1993 (Cth) (NTA). Indigenous groups may be granted

exclusive possession of, or limited access to, their traditional lands for many purposes,

including hunting, fishing, medicine, accommodation, religion and culture.662

3.4.1 Australia

In Mabo v Queensland (No 2) ("Mabo case") [1992] HCA 23; (1992) 175 CLR 1, the High

Court recognised the rights and interests to land retained under traditional laws and customs

and accepted that the Meriam people of the Torres Strait held native title rights and interests

over part of their traditional lands.663 The Mabo decision prompted the Commonwealth

Parliament to enact the NTA to provide for the recognition and protection of native title.

These native title rights can include ‘the right to possess, occupy, use and enjoy an area to the

exclusion of all others (often called the right of exclusive possession).’664 It includes the right

to control access to, and use of, the relevant area, which includes unallocated Crown land, a

reserve held for Aboriginal people and pastoral leases held by the native title parties.665 Native

title rights can be ‘non-exclusive’ rights, i.e. an area is shared by the native title holders and

other people. Western Australia’s petroleum basins are subject to both exclusive and non-

exclusive determined native title rights.666 Australia’s native title claimants have particular

rights when titles are granted inside native title claim areas.667 Native title claimants have the

662 Minerals and Energy Resource Exploration, Productivity Commission Inquiry Report, No 65, 27 September

2013, p 118 663 Mabo v Queensland (No 2) ("Mabo case") [1992] HCA 23; (1992) 175 CLR 1 (3 June 1992) at

http://www.austlii.edu.au/au/cases/cth/HCA/1992/23.html 664 Department of Mines and Petroleum, Western Australia’s Petroleum and Geothermal Explorer’s Guide –

2014 Edition, pg 112 665 Ibid. 666 Ibid. 667 National Native Title Tribunal, Negotiation, What is the right to negotiate?, (accessed 23 May 2017) at

http://www.nntt.gov.au/futureacts/Pages/Negotiation.aspx

105

opportunity to provide submissions prior to the grant of a resource title and can negotiate the

conditions in which resource titles are granted.668

Before an exploration permit is granted operators must abide by the future act provisions of the

NTA. A future act is a proposal to deal with land in a way that influences native title rights

and interests, for example the granting of a petroleum title.669 The NTA grants native title

claimants rights when titles are granted inside native title claim areas.670 Native title claimants

have a ‘right to negotiate’671 and are notified before a future act is undertaken.672 They must

be given the opportunity to make submissions673 and negotiate, in good faith, the conditions

on which petroleum titles are granted.674

Parties that agree can enter into a deed for the grant of petroleum title675 and/or ancillary

agreements that incorporate employment issues, education and training issues and aboriginal

heritage protection issues.676 When parties fail to agree they can apply to the national native

title tribunal for a determination.677 The tribunal can decide that an act must not be done, may

be done, or may be done subject to conditions.678 In Rusa Resources (Australia) Pty Ltd v

Sharon Crowe and Others on behalf of Gnulli [2015] NNTTA 26, the tribunal determined that

the conduct of Rusa did not meet the threshold for good faith.679 The tribunal was not satisfied

668 Native Title Act 1993 (Commonwealth), s 31 669 Native Title Act 1993(Commonwealth), s 29 670 National Native Title Tribunal, Negotiation, What is the right to negotiate?, (accessed 23 May 2017) at

http://www.nntt.gov.au/futureacts/Pages/Negotiation.aspx 671 Subdivision P – Right to Negotiate of the Native Title Act 1993 (Cth) at

http://www.austlii.edu.au/au/legis/cth/consol_act/nta1993147/ 672 Native Title Act 1993 (Cth), s 223 673 Native Title Act 1993 (Cth), s 31 674 Department of Mines, Industry Regulation and Safety, Western Australia’s Petroleum and Geothermal

Explorer’s Guide, 2014 Edition, pg 113 at http://www.DMIRS.wa.gov.au/Documents/Petroleum/PD-RES-

PUB-100D.pdf 675 Petroleum Division, Department of Mines and Petroleum, Guidelines for Completion of State Deed (Deed

for Grant of Petroleum Title), By Native Title Parties and Grantee Parties, (accessed 19 June 2017) at

http://www.DMIRS.wa.gov.au/Documents/Petroleum/PE-PTLA-NT-108D.pdf 676 National Native Title Tribunal, ILUA or the right to negotiate process? A comparison for mineral tenement

applications, 2008, pg 5 at http://www.nntt.gov.au/Information%20Publications/ILUA%20-

%20The%20Right%20to%20Negotiate.pdf 677 Native Title Act 1993 (Cth), s 35 678 Native Title Act 1993 (Cth), s 38 679 Rusa Resources (Australia) Pty Ltd v Sharon Crowe and Others on behalf of Gnulli [2015] NNTTA 26 (16

July 2015)

106

that Rusa negotiated in the manner required by the tribunal and resolved that they were not

empowered to deal with the application and the application was dismissed.680

Indigenous Land Use Agreements (ILUAs) are voluntary, legally binding agreements that

relate to the use and management of land made between native title parties, operators and

governments. An ILUA contains, amongst other things, agreements about a future act or group

of future acts, compensation for loss or impairment of native title, the coexistence of native

title rights and interests, access, extinguishment of native title, framework agreements and the

exercise of native title rights and interests.681

The NTA provides for three types of ILUAs, namely, body corporate agreements682, area

agreements683 and alternative procedure agreements.684 Where a native title party gives their

consent for an act to be carried out, for example, the granting of an exploration licence or

licences to an operator in an ILUA, the licence can be granted and other provisions, for example

the right to negotiate provisions of the NTA, do not apply.

Operators have obligations under the Aboriginal Heritage Act 1972 (WA) and Aboriginal

Heritage Act 1988 (SA) respectively. For example, in Western Australia, an operator commits

an offence if they excavate, destroy, damage, conceal or in any way alter a site or deal with an

object on or under a site.685 Where an activity has the potential to impact a site, the approval

of the Minister must be obtained.686 This consent specifies that the activity has been approved

and sets out where it can be undertaken.687

Western Australia’s Aboriginal Affairs Planning Authority Act 1972 (WA) is concerned with

reserved lands in Western Australia.688 The Act sets out that an application for the grant of a

680 Native Title Act 1993 (Cth), s 148(a) 681 National Native Title Tribunal, Steps to an indigenous land use agreement, 2008, pg 7 at

http://www.nntt.gov.au/Information%20Publications/Steps%20to%20and%20Indigenous%20Land%20Use%2

0Agreement.pdf 682 Native Title Act 1993 (Cth), s 24BA 683 Native Title Act 1993 (Cth), s 24CA 684 Section 24DA of the Native Title Act 1993 (Cth), s 24DA 685 Aboriginal Heritage Act 1972 (WA), s 17 686 Aboriginal Heritage Act 1972 (WA), s 18 687 Ibid. 688 Aboriginal Affairs Planning Authority Act 1972 (WA), Part III

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licence or title under the PGERA on reserved land should not be refused without prior consent,

689 or processed without consultation with the Authority,690 and shall be taken to be approved

unless the approval of the Authority, and any terms and conditions to which it may be subject

is referred to in the document evidencing the grant.691 Nothing in the Act affects or is to be

taken to detract from the operation of the PGERA.692 The authority has the power to grant a

lease over land whenever vested in the authority under this Act.693

South Australia’s Aboriginal Lands Trust Act 2013 (SA) deals with mining operations

(including gas operations) on trust land.694 A mining authority must not be granted or renewed

under the PGEA in relation to trust land except to a person who has permission to carry out

regulated activities on trust land.695 Prior to the granting or renewal of a mining authority to

engage in a regulated activity under the PGEA, the Minister must allow the trust a reasonable

opportunity to make submissions relating to the conditions subject to which the mining

authority should be granted or renewed.696 An operator who has permission to carry out

regulated activities on trust land is not required to serve on the trust a notice of entry pursuant

to state’s gas legislation.697 An operator who carries out regulated activities without

permission, or enters trust land for the purpose of carrying out regulated activities, is guilty of

offence.698

South Australia’s Anangu Pitjantjatjara Yankunytjatjara Land Rights Act 1981 (SA) grants

specific land and other rights to the Anangu Pitjantjatjara Yankunytjatjara people in the states

north/north west. The Maralinga Tjarutja Lands Rights Act 1984 (SA) granted freehold title

to about 81 373 square kilometres to the Maralinga Tjarutja people in fee simple. The

Maralinga Tjarutja Lands Rights Act 1984 (SA) caps the compensation amount for exploration

disturbance to the lands and the Aboriginal people and their way of life, to a sum no greater

than the amount available under the Mining Act 1971(SA) and PGEA.

689 Aboriginal Affairs Planning Authority Act 1972 (WA), s 30(1)(a) 690 Aboriginal Affairs Planning Authority Act 1972 (WA), s 30(1)(b) 691 Aboriginal Affairs Planning Authority Act 1972 (WA), s 30(1)(c) 692 Aboriginal Affairs Planning Authority Act 1972 (WA), s 30(2) 693 Aboriginal Affairs Planning Authority Act 1972 (WA), s 33A 694 Aboriginal Lands Trust Act 2013 (SA), s 51(c) 695 Aboriginal Lands Trust Act 2013 (SA), s 52(1) 696 Aboriginal Lands Trust Act 2013 (SA), s 52(2) 697 Petroleum and Geothermal Energy Act 2000 (SA), s 61 698 Aboriginal Lands Trust Act 2013 (SA), s 53(1)

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3.4.2 The United States

In the United States Indian trust lands and reservations are regulated (along with other

legislation) under the Section 397 of the U.S Code which states that:

Where lands are occupied by Indians who have bought and paid for the same, and

which lands are not needed for farming or agricultural purposes, and are not desired

for individual allotments, the same may be leased by authority of the council speaking

for such Indians, for a period not to exceed five years for grazing, or ten years for

mining purposes in such quantities and upon such terms and conditions as the agent in

charge of such reservation may recommend, subject to the approval of the Secretary

of the Interior.699

Indian tribes are estimated to hold three per cent of the known oil and gas reserves and in 2000,

the Department of the Interior managed 3772 mineral leases, licenses, permits and applications

on more than two million acres of Indian lands.700 In United States v Shoshone Tribe of Indians,

304 U.S. 111 (1938) the Supreme Court determined that that when lands were reserved or set

aside for tribes in executive order, treaties or agreements approved by Congress, the tribes held

the beneficial rights to the soil and mineral interests under the lands.701 As a result, on Indian

trust lands, tribes retain ownership of the mineral resources, including gas and oil.702

Any land impacted by the Indian General Allotment Act of 1887 (United States) must be

examined to determine who holds the mineral title.703 The intention of the Act was to separate

the mineral rights from the tribes by assigning tribal lands to individual members of the tribe

which allowed them to sell off lands in fee simple after a certain period of time.704 The mineral

estate was included in the fee simple title, which meant there was an alienation of mineral rights

699 Section 397, Title 25, Chapter 12 of the U.S Code at https://www.law.cornell.edu/uscode/text/25/397 700 University of Colorado at Boulder, Intermountain Oil and Gas BMP Project, Indian Land, (accessed 15 June

2017) ay < http://www.oilandgasbmps.org/laws/tribal/> 701 United States v Shoshone Tribe of Indians, 304 U.S. 111 (1938) 702 Ibid. And see generally University of Colorado at Boulder, Intermountain Oil and Gas BMP Project, Indian

Land, [(accessed 15 June 2017) < http://www.oilandgasbmps.org/laws/tribal/> 703 University of Colorado at Boulder, Intermountain Oil and Gas BMP Project, Indian Land, (15 June 2017) at

< http://www.oilandgasbmps.org/laws/tribal/> 704 Indian General Allotment Act 1887 (United States) and see generally University of Colorado at Boulder,

Intermountain Oil and Gas BMP Project, Indian Land, (accessed 15 June 2017) at <

http://www.oilandgasbmps.org/laws/tribal/>

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from tribal and tribal member ownership. Often land was sold to non-Indians. The United

States congress terminated the General Allotment Act of 1887 in 1934. Since this time,

Congress has been working with tribes to re-amalgamate former tribal trust lands. However,

many are still impacted by these policies.705

The Leasing and Grazing Act of 1891 (United States) confirmed congressional consent on non-

Indian mineral leasing on tribal land and allowed 10 year leases with tribal consent. The Indian

Mineral Leasing Act of 1938 (United States) created a single set of leasing procedures for

mineral development on tribal land. This Act was aimed at promoting self-governance by

guaranteeing a fair return on tribal minerals.706 At the federal level, the United States Code

states that where land is inhabited by Indians who have purchased it and it is not required for

agricultural purposes and not wanted for individual allotments, it may be leased for a period

not exceeding five years for mining purposes.707

The Mineral Leasing Act of 1920 (United States) (the MLA) and the Mineral Leasing Act for

Acquired Land of 1947 (United States) contain provisions for private land where mineral rights

have been retained by the federal government (split estate lands). The MLA guides the land

use planning, leasing, bonding, operations and reclamation associated with all development of

federal oil and natural gas resources. The Onshore Order No.1 (2007)708 also contains surface

owner protection provisions. A mineral owner must show due regard for the interests of the

surface owner and inhabit only those sections of the surface that are necessary to develop the

resource.709

Tribal governments in the United States have started to regulate gas development via the

enactment of tribal codes, ordinances, constitutions and best management practices.710 For

705 University of Colorado at Boulder, Intermountain Oil and Gas BMP Project, Indian Land, (accessed 15 June

2017) at < http://www.oilandgasbmps.org/laws/tribal/> 706 Ibid. 707 Section 397, Title 25, Chapter 12 of the United States Code, at

https://www.law.cornell.edu/uscode/text/25/397 708 Onshore Oil and Gas Order, The Order, No.1, Onshore Oil and Gas Operations; Federal and Indian Oil and

Gas Leases; Approval of Operations, 2007 at

http://www.blm.gov/style/medialib/blm/wo/MINERALS__REALTY__AND_RESOURCE_PROTECTION_/e

nergy/onshore_order_videos.Par.62610.File.dat/Onshore_Order_No_1_The_Order.pdf 709 Bureau of Land Management, Split Estate, (accessed 18 May 2017) at

<http://www.blm.gov/wo/st/en/prog/energy/oil_and_gas/best_management_practices/split_estate.html> 710 University of Colorado at Boulder, Indian Law, (accessed 15 June 2017) at

http://www.oilandgasbmps.org/laws/tribal/

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example, the Exploration & Production Operator’s Manual provides guidance to operators on

how to obtain well drilling authorisations, right of way easements and surface leases.711 In

Colorado, tribal governments have started to regulate gas development via the enactment of

tribal codes, ordinances, constitutions and best management practices.712 The Exploration &

Production Operator’s Compliance Manual for Energy Development Projects on the Southern

Ute Indian Reservation regulates operators when they seek to obtain authorisation to drill a gas

well, right-of-way easements and surface leases.713

The COGCC rules do not apply to Indian trust lands and minerals or the Southern Ute Indian

tribe within the exterior boundaries of the Southern Ute Indian reservation.714 The rules apply

to non-Indians conducting gas operations on lands within the exterior boundaries of the

Southern Ute Indian reservation where the surface and gas estates are owned by operators other

than the Southern Ute Indian Tribe.715 Indian trust lands and reservations are regulated under

the United States Code.716

3.5 Environmental approvals and assessment

3.5.1 Western Australia

Operators in Western Australia must submit environment plans (EP) to the DMIRS prior to

commencement of operations.717 EP’s are management documents designed to show that all

environmental risks and impacts linked with petroleum and/or geothermal activities are

711 Southern Ute Indian Tribe Growth Fund Department of Energy, The Exploration & Production Operator’s

Compliance Manual for Energy Development Projects on the Southern Ute Indian Reservation, (15 March

2018) at http://www.suitdoe.com/Documents/EPOperatorsComplianceManual.pdf 712 University of Colorado at Boulder, Intermountain Oil and Gas BMP Project, Indian Land, (accessed 15 June

2017) at < http://www.oilandgasbmps.org/laws/tribal/> 713 University of Colorado at Boulder, Southern Ute Tribe Laws, (accessed 15 June 2017) at

http://www.oilandgasbmps.org/laws/tribal/southernute.php 714 Rule 2011 of the COGCC 715 Oil and Gas, Oil and Gas Pooling, (accessed 12 June 2017) at http://www.oil-gas-leases.com/oil-gas-

pooling.html 716 Section 397, Title 25, Chapter 12 of the United States Code, at

https://www.law.cornell.edu/uscode/text/25/397 717 Petroleum and Geothermal Energy Resources (Environment) Regulations 2012 (WA) reg 6.

111

reduced to as low as reasonably practicable and carried out in a way that is consistent with the

principles of ecologically sustainable development.718

An operator must provide a summary of the approved plan to the Minister for public

disclosure.719 An environmental plan deemed suitable for the nature and scale of the activity

will be approved.720 Plans must establish that the impacts and risks will be reduced to as low

as is reasonably practicable and of an acceptable level, provide for appropriate environmental

performance objectives, include environmental performance standards and measurement

criteria, include an implementation strategy and monitoring, recording and reporting

arrangements.721 An operator must include a description of the activity including its location,

construction and layout of gas facilities, operational details, proposed timetables and any

additional information relevant to consideration of the environmental impacts and

environmental risks of the activity.722

EPs must describe the existing environment that may be affected and include details of any

specific values and sensitivities.723 They must include details of impacts and risks, an

evaluation of those impacts and risks and a description of the risk assessment process used to

evaluate those impacts and risks.724 An EP must describe the requirements that apply to the

activity under legislation, international conventions or agreements, or applicable codes of

practice that are relevant to the environmental management of the activity.725 An operator

must provide a copy of their corporate environmental policy, a report on all consultations

between themselves and relevant authorities and other relevant persons and organisations in

the course of developing the environment plan and a list of all incidents that are classified as

reportable incidents in relation to the activity.726

718 Department of Mines, Industry Regulation and Safety, Lodge an Environment Plan, (accessed 20 June 2017)

at http://www.dmp.wa.gov.au/Environment/Environment-Plan-6129.aspx 719 Petroleum and Geothermal Energy Resources (Environment) Regulations 2012 (WA) reg 11(7). 720 Id s 11 721 Petroleum and Geothermal Energy Resources Act 1967 (WA), s 11 722 Id s 14(1) 723 Id s 14(2) 724 Id s 14(3) 725 Id s 14(6) 726 Id s 17

112

The summary plan must include specific information relating to the disclosure of chemicals

used in drilling or hydraulic fracturing activities.727 The summary that is published and

available to the public includes details of the proposed activity and environmental

considerations, while the complete plan which includes the full risk assessment and

implementation strategy is not publicly available and is assessed by the DMIRS internally.728

The public can access the summary on the DMIRS website.

The EP binds the operators to certain environmental performance objectives, standards and

criteria which the operator is assessed against by the DMIRS.729 If an operator becomes aware

of a new or increased risk, they must submit a revised EP to the DMIRS for consideration.730

The purpose of the plan is to identify systems, practices and procedures that guarantee that

environmental impacts and risks are reduced to ‘as low as is reasonably practicable’.731

If an operation is considered likely to have a significant effect on the environment, it can be

referred to the Environmental Protection Authority (EPA) for assessment.732 The EPA

conducts environmental impact assessments on proposals of environmental significance,

directed by the test set out in its Environmental Impact Assessment Administrative Procedures

2012.733 The EPA can determine whether or not to assess referred proposals.734 The DMIRS

refers proposals to the EPA that could, if put into effect, have a significant effect on the

environment.735 The EPA evaluates hydraulic fracturing proposals that it considers likely to

have a significant environmental impact.736 In deciding whether to assess a proposal, the

significance of the anticipated environmental impacts, including cumulative impacts, is

727 Petroleum and Geothermal Energy Resources (Environment) Regulations 2012 (WA) reg 15(9) 728 Department of Mines and Petroleum (WA), Summary of Comments and Departmental Responses from

Public Consultation for New Environment Regulations: Petroleum and Geothermal Environment Regulations

and Guidelines for Preparation and Submission of an Environment Plan (August 2012). 729 Department of Mines and Petroleum (WA), Guidelines for the Preparation and Submission of an

Environment Plan (28 August 2012) 10. 730 Petroleum and Geothermal Energy Resources (Environment) Regulations 2012 (WA) reg 8(2). 731 Petroleum and Geothermal Energy Resources (Environment) Regulations 2012 (WA) reg 15(3)(a). 732 Environmental Protection Act 1986 (WA) 733 Environmental Protection Authority (WA), Environmental Impact Assessment Administrative Procedures

(2012) 5943-5944 at http://www.epa.wa.gov.au/EIA/assessdev/Pages/EIAAdministrativeProcedures.aspx 734 Environmental Protection Act 1986 (WA), s 39(a). 735 Environmental Protection Act 1986 (WA) s 38 736 Environmental Protection Authority, Hydraulic fracturing for onshore natural gas from shale and tight rocks,

Environmental Protection Bulletin No.22, (accessed 17 June 2016) at

http://edit.epa.wa.gov.au/EPADocLib/EPB22-Fracking-171214.pdf

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considered.737 The EPA does not approve proposals, although the process it undertakes

provides a mechanism where impacts are contemplated.738

An assessment may be carried out irrespective of whether a project is in the proof-of-concept

stage, e.g. a proof-of-concept proposal involving multiple wells in a location where inadequate

environmental information is on hand may be formally assessed.739 The EPA applies

environmental factors and objectives as the foundation for determining whether impacts are

tolerable.740 The EPA considers the impacts associated with hydraulic fracturing proposals

consistent with other proposals.741

The EPA may consider the ‘values, sensitivity and quality of the environment which is likely

to be impacted, the extent (intensity, duration, magnitude and geographic footprint) of the

likely impacts; consequence of the likely impacts (or change); resilience of the environment to

cope with the impacts or change; cumulative impact with other projects; level of confidence in

the prediction of impacts and the success of proposed mitigation; objects of the Act, policies,

guidelines, procedures and standards against which a proposal can be assessed; presence of

strategic planning policy framework; presence of other statutory decision-making processes

which regulate the mitigation of the potential effects on the environment to meet the EPA’s

objectives and principles for EIA; and public concern about the likely effect of the proposal, if

implemented, on the environment.’742

The DMIRS and the EPA communicate at pre-referral stages in cases where consultation

benchmarks are triggered and/or where there is the chance of a significant environmental

impact.743 The onshore criteria include hydraulic fracturing exploration and development

737 Ibid. 738 Ibid. 739 Ibid. 740 Environmental Protection Authority, Environmental Assessment Guideline No. 8, Environmental

Assessment Guideline for Environmental factors and objectives, 2013 at

http://www.epa.wa.gov.au/EPADocLib/EAG%208%20Factors%20and%20objectives2013.pdf 741 Environmental Protection Authority, Hydraulic fracturing for onshore natural gas from shale and tight rocks,

Environmental Protection Bulletin No.22, (accessed 17 June 2016) at

http://edit.epa.wa.gov.au/EPADocLib/EPB22-Fracking-171214.pdf 742 Environmental Impact Assessment (Part IV Divisions 1 and 2) Administrative Procedures 2012 743 Memorandum of Understanding between the DMIRS and EPA, (accessed 19 June 2017) pg 2 at

http://www.dmp.wa.gov.au/Documents/Environment/ENV-MEB-016.pdf

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activities.744 The DMIRS and EPA have a Memorandum of Understanding (MOU).745 The

MOU sets out the procedure for communicating before referring a proposal (which includes

Programme of Works (exploration), Mining Proposals and EP’s to determine if proposals

should be formally referred.746 The EPA have made determinations not to assess referred

proposals because they were deemed small proof-of-concept activities and their impacts could

be adequately managed by the DMIRS through the implementation of EPs.747 It is not clearly

stated in the MOU that it covers both petroleum and geothermal activities. The DMIRS can

refer projects to the Department of Water and Environmental Regulation (DoWER) for water-

related advice under an administrative agreement.748

The DMIRS also refers projects to the DoWER for water resources advice. The DoWER

assesses, issues and controls water licences under the Rights in Water and Irrigation Act 1914

(WA) (the RiWI Act). The DoWER provides specialist and technical water advice to the

DMIRS as part of the DMIRS approvals processes, assists the EPA by the same advice on

referrals, provides advice as required to the Appeals Convenor and grants water licences or

permits for operators to take water needed for hydraulic fracturing. The approvals processes

under the various pieces of legislation require petroleum operators to identify and manage

environmental impacts.

3.5.2 South Australia

The PGEA sets a clear role for the public in identifying potential risks of a proposed activity,

and the environmental outcomes to be achieved under a Statement of Environmental Objectives

(SEO). All activities regulated under the PGEA are also subject to the provisions of the Natural

Resources Management Act 2004 (SA) (NRMA) and the Environment Protection Act

1993(SA). Regulated activities must not be carried out unless an approved SEO is in place,

prepared on the basis of an Environmental Impact Report (EIR).749

744 Ibid. 745 Ibid. 746 Id at 3. 747 Environmental Protection Authority (WA), Environmental Protection Bulletin No 15 – Hydraulic Fracturing

of Gas Reserves (2011) 3. 748 Department of Water, Water and the shale and tight gas industry, (accessed 15 June 2017) at

https://www.water.wa.gov.au/__data/assets/pdf_file/0020/7841/109620.pdf 749 Petroleum and Geothermal Energy Act 2000, s 97

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The EIR describes the detailed characteristics of the environment where the activities will take

place and identifies potential impacts, risks and the proposed risk-mitigation strategies. The

SEO sets out the environmental objectives to be achieved to address the risks identified in the

EIR and the criteria to be used to assess achievement of the objectives. The EIR and SEO are

expected to deal with, amongst other things, impacts on aquifers, including pressure and

contamination, impacts on groundwater use, contamination of surface water and shallow

groundwater, water storage ponds, flow-back storage ponds, disturbance to existing land uses

and remediation and rehabilitation requirements.750

An SEO must be prepared for low impact or medium impact activities on the basis of an EIR

and for high impact activities on the basis of an EIA.751 An operator must set out project

objectives, the criteria that will be applied to determine whether the objectives have been

achieved, compliance requirements and reporting obligations.752 An SEO must set out how

land adversely affected by regulated activities will be rehabilitated.753 For high impact

activities, an operator must provide a report or periodic reports from an independent expert on

the environmental consequences of the activities; and may include a system for evaluating the

licensee's environmental performance.754

The PGEA contains very distinct consultation requirements. Stakeholders, including

landholders, must be informed and advised on the potential risks associated with proposed

activities, and the management strategies that will be used to minimise risk. They must be

provided with the opportunity to raise any issues of concern before regulated activities

commence. The DPC (SA) anticipates that licensee’s will initiate consultation with

stakeholders prior to and during the development of their EIR and SEO, to describe their

activities and the potential impacts which may be experienced.

The PGEA has a much more robust environmental management regime than the PGERA.

Although a Western Australian operator must describe the activities they intend to undertake

and provide information about environmental impacts and risks in terms of the existing

environment and a risk assessment process used to evaluate those impacts and risks, this

750 Petroleum and Geothermal Energy Regulations 2013 (SA) 751 Petroleum and Geothermal Energy Act 2000, s 99 752 Id s 100 753 Id s 100(2) 754 Id s 100(3)

116

information is only provided prior to the activities being carried out and does not include any

detail about post activity. In setting out how land adversely affected by regulated activities

will be rehabilitated, an SEO goes far beyond what is needed in an environmental plan.

SEOs explicitly address impacts on aquifers, impacts on groundwater use, contamination of

surface water and shallow groundwater, water storage ponds and flow-back storage ponds.

Environmental plans do not cover this to the same extent. An object of the PGEA is to establish

appropriate consultative processes involving people directly affected by regulated activities

and the public generally. The PGERA is silent on consultative processes. The DMIRS (WA)

and DPC (SA) should encourage operators to submit some form of voluntary CDP similar to

that which exists in Colorado. It has been suggested that, though they are voluntary, CDPs

would be more effective if operators developed joint CDPs to cover the activities of multiple

operators755 Western Australia and South Australia lag behind Colorado in terms of facilitating

discussion with stakeholders around potential impacts and harm minimisation measures.

During exploration in South Australia, the EPA (SA) provides advice to DPC (SA). The EPA

(SA) regulates off site activities linked to exploration under the Environment Protection Act

1993 (SA), for example the transport of waste and disposal requirements. The Environment

Protection Act 1993 (SA) applies to operators undertaking petroleum production activities. The

EPA (SA) works with DPC to provide advice through their SEO and EIR process. The EPA

(SA) is a mandatory referral agency under the Petroleum and Geothermal Energy Regulations

2000 (SA). Where exploration activity is referred to the EPA (SA) for assessment and

comment, the EPA (SA) considers whether the proposed risk ranking is appropriate, and

advises DPC (SA) accordingly. Above certain thresholds756, a licence from the EPA (SA) is

required to undertake activities. The EPA (SA) and DPC (SA) both have a role in the

production phase, and therefore have an Administrative Arrangement (AA) and a

Memorandum of Understanding (MOU).757 The AA sets out the responsibilities of each

agency, and identifies which agency takes the lead on potential environmental incidents.

755 Keith N. Eshleman & Andrew Elmore, Recommended Best Management Practices for Marcellus Shale Gas

Development in Maryland, 2013, University of Maryland Center for Environmental Science 756 Environmental Protection Act 1993 (SA, Schedule 1 757 Administrative Arrangements (accessed 17 May 2018) <

http://minerals.statedevelopment.sa.gov.au/mining/mining_regulation_in_south_australia/administrative_arran

gements>

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South Australia’s Department of Environment, Water and Natural Resources (DEWNR) is a

referral agency under the PGEA and is provided with SEOs for comment and advice on a range

of matters, including water issues related to petroleum production. The NRMA provides the

statutory framework requiring the sustainable and integrated management of water. Water

resources that are highly valued are prescribed to protect their integrity and ensure proper

management and sustainable use. Prescribed water resource areas are managed through a water

allocation plan (WAP) that sets the limit on the volume of water that can be taken and used. A

water licence is required to take water from a prescribed area, under the conditions set in the

relevant WAP.

3.5.3 Colorado

The COGCC consults with the Department of Public Health and Environment (CDPHE) when

it receives an Application for Permit-to-Drill758, Oil and Gas Location Assessment759 where a

local government requests CDPHE participation in COGCC’s consideration760 or where an

operator seeks an adjustment from, or consultation in relation to, for example, public water

system protection761 and underground disposal of water.762 The CDPHE may suggest

monitoring requirements or best management practices.763 They may also recommend whether

a variance request should be granted.764

758 Rule 303(a)(1) of the COGCC rules at <

https://cogcc.state.co.us/documents/reg/Rules/LATEST/CompleteRules.pdf 759 Rule 303.b of the COGCC rules at <

https://cogcc.state.co.us/documents/reg/Rules/LATEST/CompleteRules.pdf 760 Rule 306.d.(1)(A)(i) of the COGCC rules at <

https://cogcc.state.co.us/documents/reg/Rules/LATEST/CompleteRules.pdf 761 Rule 317B of the COGCC rules at <

https://cogcc.state.co.us/documents/reg/Rules/LATEST/CompleteRules.pdf 762 Rule 325 of the COGCC rules at <

https://cogcc.state.co.us/documents/reg/Rules/LATEST/CompleteRules.pdf 763 Rule 306(3)(A) of the COGCC rules at <

https://cogcc.state.co.us/documents/reg/Rules/LATEST/CompleteRules.pdf 764 Rule 306(3)(A) of the COGCC rules at <

https://cogcc.state.co.us/documents/reg/Rules/LATEST/CompleteRules.pdf

118

3.6 Regulatory approaches

There are a number of regulatory approaches suited to the exploitation of shale and tight gas

that are situated somewhere between strict forms of regulation and de-regulation.765 Up until

the 1990s, command and control regulation and prescriptive approaches, both strict forms of

regulation, were the standard regulatory approaches used to manage the exploitation of

unconventional gas.766 Both have been effective in dealing with environmental issues.767

Western Australia’s approach to exploiting shale and tight gas is risk based and objective

based.768 South Australia’s approach is also risk and objective based.769 Colorado mainly uses

command and control and case by case permitting to regulate the exploitation of shale and tight

gas.770 As far as the DMIRS is concerned, command control type approaches, which are largely

prescriptive approaches, tend to become outdated and counterproductive.771

Although Western Australia’s approach to regulation is risk/objective based, it does take a

prescriptive approach to data submission and reporting.772 Some argue that there is no ideal

regulatory model.773 While this is probably correct as long as approaches are low cost, low

risk and they decrease health, safety and environmental risks and protects other public interests,

765 Rob White & Diana Heckenberg, Legislation, Regulatory Models and Approaches to Compliance and

Enforcement, Briefing Paper No.6, July 2012, pg 12 766 Olmstead, Sheila and Nathan Richardson, Managing the Risks of Shale Gas Development Using Innovative

Legal and Regulatory Approaches, Discussion Paper, Resources for the Future, June 2014, page 8 at

http://www.rff.org/files/sharepoint/WorkImages/Download/RFF-DP-14-15.pdf 767 N. Gunningham & D. Sinclair, Leaders and Laggards: Next Generation Environmental Regulation

(Sheffield: Greenleaf Publishing, 2002). 768 Department of Mines and Petroleum, Guidelines for the Petroleum and Geothernal Energy Resources

(Resource Management and Administration) Regulations 2015 and Petroleum (Submerged Lands) (Resource

Management and Administration) Regulations 2015, pg 5 769 Natural Resource Committee, Inquiry into unconventional gas fracking, Submission from the South

Australian Government, January 2015, pg 29

http://minerals.statedevelopment.sa.gov.au/_data/assets/pdf_file/0009/263457/Inquiry_into_Unconventional_G

as_Fracking_S-_SA_Government_Submission.pdf 770 Nathan Richardson, Madeline Gottlieb, Alan Krupnick, and Hannah Wiseman, The State of State Shale Gas

Regulation: Appendices, June 2013, Resource for the Future, pg 21

http://www.rff.org/files/document/file/RFF-Rpt_StateofStareRegs_Appendices_0.pdf 771 Department of Mines and Petroleum, Guidelines for the Petroleum and Geothernal Energy Resources

(Resource Management and Administration) Regulations 2015 and Petroleum (Submerged Lands) (Resource

Management and Administration) Regulations 2015, pg 5 772 For example Part 8 of the Petroleum and Geothermal Energy Resources (Resources Management and

Administration) Regulations 2015 (WA) 773 Alan Hardacre, ‘Better Regulation – What is at Stake?’ (Training Paper, European Institute of Public

Administration, 2008) 3 at http://www.eipa.eu/files/repository/eipascope/20080905132115 _SCOPE2008-

2_1_AlanHardacre.pdf

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they are likely to be effective.774 The unique social, political and geologic differences between

jurisdictions is not enough to justify some jurisdictions regulating more or less rigorously or

indeed, not regulating some elements at all.775

According to some industry commentators substantial overlap exists i.e., states may choose to

use a hybrid approach, with more than one regulatory tool for an element. For example, states

in the United States frequently use a command and control regulation to set state-wide

minimum standards but require case-by-case permit review or allow exceptions or variances

from the state wide standard upon application and approval.776 In these cases, command and

control was considered the primary form of regulation.777

3.6.1 Western Australia and South Australia – objective/risk based

Most industry commentators consider risk and objective based approaches best practice for

modern regulation.778 Western Australia’s objective based approach sits within a risk

management framework.779 The move towards an objective based approach for Western

Australia was a deliberate move away from the previous prescriptive regime contained in the

‘Schedule of Onshore Petroleum Exploration and Production Requirements -1991 (amended

21 May 2010)’ and ‘Schedule of Geothermal Exploration and Production Requirements

2009’.780

774 Ibid. 775 Nathan Richardson, Madeline Gottlieb, Alan Krupnick, and Hannah Wiseman, The State of State Shale Gas

Regulation, Executive Summary, May 2013, pg 5 776 Nathan Richardson, Madeline Gottlieb, Alan Krupnick, and Hannah Wiseman, ‘The State of State Shale Gas

Regulation’, June 2013, pg 14 at http://www.rff.org/files/sharepoint/WorkImages/Download/RFF-Rpt-

StateofStateRegs_Report.pdf 777 Ibid 778 Natural Resources Committee, Parliament of South Australia, Inquiry into unconventional gas fracking,

Submission for the South Australia Government, Department of State Development, January 2015, pg 29 at <

http://minerals.statedevelopment.sa.gov.au/__data/assets/pdf_file/0009/263457/Inquiry_into_Unconventional_

Gas_Fracking_-_SA_Government_Submission.pdf> 779 Department of Mines, Industry Regulation and Safety, Guidelines to Petroleum and Geothermal Energy

Resources (Resource Management and Administration) Regulations 2015 and Petroleum (Submerged Lands)

(Resource Management and Administration) Regulations 2015, September 2016, pg 4 780 ‘Schedule of Onshore Petroleum Exploration and Production Requirements – 1991 (WA) (Amended 21 May

2010)’; ‘Schedule of Geothermal Exploration and Production Requirements 2009 (WA)

120

The objective and risk based approaches taken in Western Australia and South Australia are

based on the belief that responsibility for achieving objectives and managing risk, through the

use of industry ‘best practice’, rests with operators.781 These approaches require operators to

achieve regulatory objectives and manage risks by broadly replicating industry ‘best

practice’.782

South Australia also uses a risk and objective based approach to exploiting shale and tight

gas.783 The focus in South Australia is on achieving environmental outcomes (on what should

be achieved not how), obligations to achieve objectives rather than it being the responsibility

of regulators. The DPC encourages operators to invent new technologies and ensures there is

‘fit for purpose’ regulation. Stakeholder input is incorporated in setting outcomes and assessing

the ability of operators to achieve outcomes.784

An objective based approach requires operators to meet legislative objectives through self-

determination i.e., it is their responsibility to advise regulators on how they plan to achieve the

objectives.785 The approach establishes key principles and objectives in legislation and

sanctions judgement, i.e. operators are allowed to put into effect principles and objectives in

an appropriate way.786 Operators must use appropriate standards to demonstrate to how

objectives are to be achieved within an acceptable risk profile.787 Some insist that an objective

781 Department of Mines, Industry Regulation and Safety, Guidelines for the Petroleum and Geothermal Energy

Resources (Resource Management and Administration) Regulations 2015 and Petroleum (Submerged Lands)

(Resource Management and Administration) Regulations 2015, pg 5 at

http://www.DMIRS.wa.gov.au/documents/PD-SBD-ADM-180D.pdf 782 Department of Mines, Industry Regulation and Safety, Guidelines to Petroleum and Geothermal Energy

Resources (Resource Management and Administration) Regulations 2015 and Petroleum (Submerged Lands)

(Resource Management and Administration) Regulations 2015, September 2016, pg 4 783 Natural Resources Committee, Parliament of South Australia, Inquiry into unconventional gas fracking,

Submission for the SA Government, Department of State Development, January 2015, pg 29 at <

http://minerals.statedevelopment.sa.gov.au/__data/assets/pdf_file/0009/263457/Inquiry_into_Unconventional_

Gas_Fracking_-_SA_Government_Submission.pdf> 784 Ibid. 785 Department of Mines, Industry Regulation and Safety, Guidelines for the Petroleum and Geothermal Energy

Resources (Resource Management and Administration) Regulations 2015 and Petroleum (Submerged Lands)

(Resource Management and Administration) Regulations 2015, pg 5 at

http://www.DMIRS.wa.gov.au/Documents/Petroleum/PD-SBD-ADM-180D.pdf 786 Taskforce on Reducing Regulatory Burdens on Business, 2006, pg 160, at

<http://www.pc.gov.au/research/supporting/regulation-taskforce/report/regulation-taskforce2.pdf> 787 Department of Mines, Industry Regulation and Safety, Guidelines for the Petroleum and Geothermal Energy

Resources (Resource Management and Administration) Regulations 2015 and Petroleum (Submerged Lands)

(Resource Management and Administration) Regulations 2015, pg 5 at

http://www.DMIRS.wa.gov.au/documents/PD-SBD-ADM-180D.pdf

121

based approach is particularly useful in complex or rapidly developing industries and the

approach suits shale and tight gas production.788

Risk has become a popular regulatory tool.789 Those that support a risk based approach insist

that it aids governance by ‘contributing to efficient and effective use of regulatory resources

and delivering interventions in proportion to risk’.790 Those who oppose it insist that its

implementation challenges diminish its potential.791 Risk is about studying ‘the causes of

disaster and failure’.792 Some insist that risk implies that there is the ‘anticipation of

catastrophe’.793 Risk based frameworks seek to control risks rather than ensuring compliance

with specific rules.794 A risk based approach focuses on risk management and risk reduction to

levels that society considers acceptable.795 The approach encourages development by offering

incentives.796 This approach requires operators to identify and moderate risks based on

likelihood and outcomes.797 The process demands that judgements are made on a number of

matters, especially on how risks are ‘bundled’.798

A key element of a risk-based approach is risk assessments that provides a risk rating. Those

activities which pose the greatest risk are often targeted with the added inspection and

enforcement regimes.799 Risk assessments are carried out during exploration, production and

788 Simon Robb, ‘A best practice regulatory proposal for shale gas production’, Doctor of Juridical Science

thesis, The University of Western Australia, 2014, pg 79 789 Rothstein H, Huber M, Gaskell G., ‘A theory of risk colonisation: the spiralling regulatory logics of societal

and institutional risk’ (2006) 35(1) Economy and Society 91 -112 790 Henry Rothstein, Phil Irving, Terry Walden and Roger Yearsley, ‘The risks of risk-based regulation: Insights

from the environmental policy domain’ (2006) 32 Environmental International 1056, 1056 791 Ibid. 792 Robert Baldwin, Martin Cave & Martin Lodge, Understanding Regulation, Theory, Strategy, and Practice

(Oxford, 2nd Edition, 2012) pg 85 793 U. Beck, ‘Living in the World Risk Society’ (2006) 35(3) Economy and Society 329-45 794 Robert Baldwin, Martin Cave & Martin Lodge, Understanding Regulation, Theory, Strategy, and Practice

(Oxford, 2nd Edition, 2012) pg 281 795 Andreas Klinke and Ortwin Renn, ’A New Approach to Risk Evaluation and Management: Risk-Based,

Precaution-Based,and Discourse-Based Strategies‘ (2002) 22 Risk Analysis 1071. 796 H Rothstein et al, ’The Risks of Risk-Based Regulation: Insights from the Environmental Policy Domain’

(2006) 32 Environment International 1056, 1056-1061. 797 Tania Murray, Dr Edward Andre and Krishna Prasad, ‘Holding fracking operations to account for

environmental contamination in risk-based regulatory regimes: Insights from the United States’ (2016) 33

EPLJ 222, 228 798 Robert Baldwin, Martin Cave & Martin Lodge, Understanding Regulation, Theory, Strategy, and Practice

(Oxford, 2nd Edition, 2012) pg 283 799 Simon Robb, ‘A best practice regulatory proposal for shale gas production’, Doctor of Juridical Science

thesis, 2014, pg 76

122

abandonment.800 Some insist that ‘regulators do not know where the next big failure will come

from, but they must act as if they do’.801 In doing so, they have to decide whether to err on the

side of doing something now that does not need to be done, ‘because it turns out later on that

it should have done’.802 A risk-based approach allocates resources according to societal risks

‘considering both the impacts themselves and the likelihood that they happen, in order to

establish appropriate levels of control.’803

A risk-based approach provides flexibility and allow for continuous improvement in response

to new scientific, technological advances and social considerations.804 In using a risk-based

approach, regulators recognise that it may be more cost-effective to allow some techniques to

fail as long as the consequence or likelihood of failure is appropriately low.805 A risk-based

approach can ‘contribute to regulatory efficiency’ and ‘help provide a defensible rationale for

decision-making’.806 Purported failings can be addressed by the use of checklists to ensure

issues are ‘identified and weighted, consistent with openly available criteria and used in

decision-making’.807

A risk-based approach to developing regulations follows on from an evaluation of hazards and

risks that influence evolving regulatory frameworks.808 This guarantees that the activities that

present the biggest risk are monitored with a combination of ‘direct’ government monitoring,

accompanied by reviewing operators’ reports.809 For example, the conditions attached to an

800 Responsible Shale Development, Enhancing the Knowledge Base on Shale Oil and Gas in Canada, Energy

and Mines Minister’s Conference, Yellowknife, Northwest Territories, August 2013, pg 25 at

https://www.nrcan.gc.ca/sites/www.nrcan.gc.ca/files/www/pdf/publications/emmc/Shale_Resources_e.pdf 801 Julia Black, The Emergence of Risk-Based Regulation and the New Public Risk Management in the United

Kingdom (P.L. Autumn © Sweet & Maxwell and Contributors,2005) pg 546 802 Ibid. 803 Henry Rothstein, Phil Irving, Terry Walden and Roger Yearsley, ‘The risks of risk-based regulation: Insights

from the environmental policy domain’ (2006) 32 Environmental International 1056, 1057 804 McFadyen, D. Regulatory Actions and Issues Energy Resources Conservation Board (ERCB) Presentation to

the Interstate Oil and Gas Compact Commission (Alberta)(June, 2011). 805DNV, Risk Management of Shale Development and Operations, DNV, (January 2013) , pg 8 at

http://www.igu.org/sites/default/files/DNV%20GL%20Report-%20Risk%20Management-Shale%20gas_0.pdf 806 Henry Rothstein, Phil Irving, Terry Walden and Roger Yearsley, ‘The risks of risk-based regulation: Insights

from the environmental policy domain’ (2006) 32 Environmental International 1056, 1061 807 Simon Robb, ‘A best practice regulatory proposal for shale gas production’, 2014, pg 78, 808 Responsible Shale Development Enhancing the Knowledge Base on Shale Oil and Gas in Canada, Energy

and Mines Ministers’ Conference Yellowknife, Northwest Territories August 2013, pg 29 at

https://www.nrcan.gc.ca/sites/www.nrcan.gc.ca/files/www/pdf/publications/emmc/Shale_Resources_e.pdf 809 Department of Energy & Climate Change, About shale gas and hydraulic fracturing (fracking), 2013, pg 21

at

123

operator’s environmental licences specify the minimum conditions for site based monitoring

and reporting.810 There are situations where prescriptive requirements, or rules, are required,

or where prescription will reduce regulatory burdens by providing operators with a well-

defined focus about what they are required to do to simplify and standardise there

administrative processes.811

Some industry commentators argue that regulatory frameworks should be reinforced by two

main pillars: risk-based approach and play-based approach – the risk-based approach provides

a flexible approach to account for the variability of unconventional gas reservoirs, while the

play-based approach provides a science based approach to organizing the risks of development

around a play (such as, geology, location, reservoir properties).812

3.6.2 Colorado – command & control and case by case permitting

In the United States, a great deal of federal and state environmental law strongly fits the

command and control regulatory approach.813 In 2013, Resources for Future published a

report titled, ‘The State of State Shale Gas Regulation’.814 The report surveyed twenty five

elements of the shale gas exploitation process in 31 states.815 The authors note that the ‘review

https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/268017/About_shale_gas_and_

hydraulic_fracturing_Dec_2013.pdf 810 Department of Energy & Climate Change, About shale gas and hydraulic fracturing (fracking), 2013, pg 21

at

https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/268017/About_shale_gas_and_

hydraulic_fracturing_Dec_2013.pdf 811 Department of Mines, Industry Regulation and Safety, Guidelines for the Petroleum and Geothermal Energy

Resources (Resource Management and Administration) Regulations 2015 and Petroleum (Submerged Lands)

(Resource Management and Administration) Regulations 2015, pg 5 at

<http://www.DMIRS.wa.gov.au/documents/PD-SBD-ADM-180D.pdf> 812 McFadyen, D. Regulatory Actions and Issues Energy Resources Conservation Board (ERCB)

Presentation to the Interstate Oil and Gas Compact Commission (Alberta)(June, 2011).

813 David A Dana & Hannah J. Wiseman, ‘A Market Approach to Regulating the Energy Revolution: Assurance

Bonds, Insurance, and the Certain and Uncertain Risks of Hydraulic Fracturing’ (2015) 99 Iowa Law Review

1523, 1547 814 Nathan Richardson, Madeline Gottlieb, Alan Krupnick, & Hannah Wiseman, The State of State Shale Gas

Regulation, June 2013, pg 8 at http://www.rff.org/files/sharepoint/WorkImages/Download/RFF-Rpt-

StateofStateRegs_Report.pdf 815 Ibid.

124

is broad but necessarily incomplete – fully describing even one state’s shale gas-related

regulations would probably take multiple volumes and would need to be updated frequently’.816

The authors selected and reviewed general well spacing, building setback, water setback, pre-

drilling water well testing, casing/cementing depth, cement type production, surface,

intermediate and production casing cement circulation, water withdrawals, fracking fluid

disclosure, fluid storage options, freeboard, pit liners, underground injection, fluid disposal

options, wastewater transport tracking, venting, flaring, severance taxes, well idle time limits,

temporary abandonment, accident reporting, bans and moratoria and regulatory agencies.817

The ‘elements in the analysis were selected to give an overview of common regulations

throughout the shale gas development process and are sufficient…to give an accurate general

picture of the state of state regulation…our data do not include federal, local, or, for the most

part, state level regulation that does not apply state-wide (i.e., field-specific rules)’.818

Of the 20 elements examined in Colorado, command and control was used to administer 18.819

For example, command and control is used to administer pre-drilling water well testing, water

withdrawal restrictions, setback restrictions from buildings, setback restrictions from water

sources, casing and cementing depth requirements, surface, intermediate and production casing

cement circulation regulations, venting and flaring regulations, fracking fluid disclosure

regulations, underground fluid injection and temporary abandonment.820 A permit was needed

to administer one element (water withdrawal restrictions) and no evidence of regulation was

found in one case (cement type regulations).821

Command and control regulation comprises highly prescriptive rules requiring regulatory

bodies to do specific things without regard to special circumstances, economic conditions, and

the like.822 It is characterised by legislation and the development of rules (‘or commands’)

816 Id at 1. 817 Id at 9. 818 Id at 8. 819 Id at 21. 820 Ibid. 821 Ibid. 822 Id at 5.

125

administered by regulatory bodies acting under legislative authority.823 Rules are specific and

operators are required to comply with them.824 Activities are managed through the

identification of potential risks and a determination of how operators will control them.825

Command and control regulation is accompanied by the ability of regulators to fine operators

if they fail to comply with rules, order operators to comply and terminate their operations.826

A command and control approach to regulation involves the utilisation of ‘best practices’ to

reduce external harms.827 Operators are required to implement ‘state of the art’ practices i.e.,

practices that are more rigorous (technically advanced and economically viable) than common

practices.828 This type of regulation is based on the premise that ‘if some producers can operate

profitably whilst providing certain harm-preventing measures, all producers should be required

to do so’.829 Although command and control regulation provides less protection than banning

activities outright, it does provide reassurance to the public.830

Some industry commentators insist that the problem with command and control regulation is

the sanctioning of inefficient rules that are developed with regard to current technology rather

than rigorous assessment of costs and benefits.831 A command and control approach to

regulation often results in over-regulation, a burden, or in under-regulation, an excessive

823 David A Dana & Hannah J. Wiseman, ‘A Market Approach to Regulating the Energy Revolution: Assurance

Bonds, Insurance, and the Certain and Uncertain Risks of Hydraulic Fracturing’ (2015) 99 Iowa Law Review

1523, 1547 824 Ibid. 825 Simon Robb, A Best Practice Regulatory Proposal for Shale Gas Production, Doctor of Juridical Science

thesis, The University of Western Australia, 2013, pg 73 826 David A Dana & Hannah J. Wiseman, ‘A Market Approach to Regulating the Energy Revolution: Assurance

Bonds, Insurance, and the Certain and Uncertain Risks of Hydraulic Fracturing’ (2015) 99 Iowa Law Review

1523, 1547 827 Thomas W. Merrill & David M. Schizer, ‘The Shale Oil and Gas Revolution, Hydraulic Fracturing, and

Water Contamination: A Regulatory Strategy’ (2013) Minnesota Law Review 206 828 Restatement (Third) of Torts: Products Liability § 2, cmt. d. (1996) Cornell Journal of Law and Public

Policy, Volume 5, Issue 2, Winter, See, e.g., The T.J. Hooper, 60 F.2d 737 (2d Cir. 1932) (holding that it was

negligent for coastal tug to operate without a radio receiver given that some tug boat operators in the industry

provided radio receivers for their vessels). 829 For water pollution, these are called “effluent standards.” 33 United States.C. § 1314(b) (2006). Effluent

standards, like best practices regulations, are generally set using existing technology as the relevant

benchmark. Once the relevant range of standards is identified based on existing technology, however, it is

possible to use cost-benefit analysis in selecting among appropriate technological benchmarks. See, e.g.,

Entergy Corp. v. Riverkeeper, Inc., 556 United States. 208, 226 (2009). 830 Thomas W. Merrill & David M. Schizer, ‘The Shale Oil and Gas Revolution, Hydraulic Fracturing, and

Water Contamination: A Regulatory Strategy’ (2013) Minnesota Law Review 206 831 Thomas W. Merrill & David M. Schizer, ‘The Shale Oil and Gas Revolution, Hydraulic Fracturing, and

Water Contamination: A Regulatory Strategy’ (2013) Minnesota Law Review 207

126

risk.832 Command and control can discourage innovation by restricting best practices at a point

in time.833 Some industry commentators argue that operators are likely to prefer command and

control regulation as it provides reasonably foreseeable regulatory costs.834

Command and control is ideal for the early stages of regulatory intervention.835 Some industry

commentators insist that using a command and control approach can, to some extent, alleviate

the concerns of those vehemently opposed to an activity.836 This approach allows regulators to

set clear limits and to administer them within a legislative framework.837 It has been suggested

that command and control regulation, once implemented, can lead to community

disengagement and increased industry distrust.838. Furthermore, some suggest that command

and control has the tendency to encourage a system that requires the need for excessive

conformity, where ‘layer upon layer’ of strict rules impact unreasonably upon operators,

inhibiting managerial innovation and decision making.839

Prescriptive requirements, or rules, provide operators with a clear understanding of what they

must do, thus streamlining and regulating administrative processes.840 Western Australia has a

degree of prescriptive regulation for the content and layout requirements for various approval

applications, reports and data.841 The purpose is to provide a ‘checklist’ which covers topics

that an operator must consider in the provision of information for a submission.842 Some insist

that there needs to be a balance between prescriptive regulation and performance based

832 See, e.g., Bruce A. Ackerman & Richard B. Stewart, ‘Reforming Environmental Law’ (1985) 37 Stan. L.

Rev. 1333, 1335–37 833 Thomas W. Merrill & David M. Schizer, ‘The Shale Oil and Gas Revolution, Hydraulic Fracturing, and

Water Contamination: A Regulatory Strategy’ (2013) Minnesota Law Review 207 834 Ibid. 835 Robert Baldwin and Martin Cave, Understanding Regulation – Theory, Strategy and Practice (Oxford Press,

1999), 35 836 Ibid. 837 Ibid. 838 Simon Robb, ‘A best practice regulatory proposal for shale gas production’, 2014, pg 75 at 839 Ibid. 840 Department of Mines, Industry Regulation and Safety, Guidelines for the Petroleum and Geothermal Energy

Resources (Resource Management and Administration) Regulations 2015 and Petroleum (Submerged Lands)

(Resource Management and Administration) Regulations 2015, pg 5 at

http://www.DMIRS.wa.gov.au/documents/PD-SBD-ADM-180D.pdf 841 For example, Part 8 of the Petroleum and Geothermal Energy Resources (Resource Management and

Administration) Regulations 2015 (WA) 842 Department of Mines, Industry Regulation and Safety, Guidelines for the Petroleum and Geothermal Energy

Resources (Resource Management and Administration) Regulations 2015 and Petroleum (Submerged Lands)

(Resource Management and Administration) Regulations 2015, pg 5 at

<http://www.DMIRS.wa.gov.au/documents/PD-SBD-ADM-180D.pdf>

127

regulation (objective based) to guarantee high standards while encouraging innovation and

technological improvement.843 Performance based standards enable operators to be flexible.844

The move from prescriptive regulation to other types of regulation is the result of the suggestion

that, given the unconventional gas sector is subject to rapid technological change, prescriptive

regulations are prone to becoming redundant and counterproductive in their intended role.845

There is also recognition that in circumstances where governments attempt to prescribe through

legislation appropriate measures to minimise risk, governments assume a role in risk

minimisation.846

Case by case permitting involves formal processes and regulatory review.847 Decision making

rests entirely with regulators and allows variable risks to be addressed.848 The goal is to prevent

operators from avoiding regulation through technical compliance only; i.e., they comply with

regulations technically but not with the spirit of them.849 Case-by-case permitting affords

operators great flexibility but also requires the greatest regulatory resources.850 The approach

is considered administratively costly given permits are reviewed, though some insist that they

may not be uniformly enforced.851 It is suggested that case-by-case permitting lacks

transparency given it is hard and often impossible to know in advance what is necessary for

permit approval, or for ‘onlookers’ to gauge regulatory requirements and stringency.852 There

843 World Energy Outlook, Golden Rules for a Golden Age of Gas, World Energy Outlook Special Report on

Unconventional Gas, 2011, pg 47 at

http://www.worldenergyoutlook.org/media/weowebsite/2012/goldenrules/WEO2012_GoldenRulesReport.pdf 844 Nathan Richardson, Madeline Gottlieb, Alan Krupnick, & Hannah Wiseman, The State of State Shale Gas

Regulation, Executive Summary, May 2013, pg 5 845 Department of Mines and Petroleum, Guidelines to Petroleum and Geothermal Energy Resources (Resource

Management and Administration) Regulations 2015 and Petroleum (Submerged Lands) (Resource

Management and Administration) Regulations 2015 (September 2016), pg 4 at

http://www.dmp.wa.gov.au/Documents/Petroleum/PD-SBD-ADM-180D.pdf 846 Ibid. 847 Nathan Richardson, Madeline Gottlieb, Alan Krupnick, & Hannah Wiseman, ‘The State of State Shale Gas

Regulation’, June 2013, pg 14 at http://www.rff.org/files/sharepoint/WorkImages/Download/RFF-Rpt-

StateofStateRegs_Report.pdf 848 Hannah Wiseman, Evaluating and Enhancing the Capacity of the States to Govern Unconventional Oil and

Gas Development Risks, (2014) at

http://sites.nationalacademies.org/cs/groups/dbassesite/documents/webpage/dbasse_084382.pdf 849 Nathan Richardson, Madeline Gottlieb, Alan Krupnick, & Hannah Wiseman, ‘The State of State Shale Gas

Regulation’, June 2013, pg 14 at < http://www.rff.org/files/sharepoint/WorkImages/Download/RFF-Rpt-

StateofStateRegs_Report.pdf> 850 Id at 15. 851 Id at 14. 852 Ibid.

128

is little evidence to suggest that case-by-case permitting is less strict or less effective than the

command-and-control approach or performance standards.853

3.6.3 Other regulatory approaches

Self-regulation sees operators develop and self-enforce rules which have been agreed to by a

collective membership for the purpose of mutual benefit.854 Some insist that self-regulation

should be adopted to avoid the burden of government regulatory interference or maintain

standards or reputation.855 It is suggested that self-regulation might fill gaps in regulatory

agendas and even promote advanced levels of environmental responsibility and governance.856

In order to achieve self-regulation, industries need to manage the process, that is, find solutions

to problems, whether actual of perceived, in the absence of oversight from government (or

regulatory bodies).857

Self-regulation allows operators to make decisions to prevent environmental impacts, to

monitor shale and tight gas production sites, and determine how to protect the public.858 Some

argue that self-regulation is ineffective and does little to establish a social licence to operate.859

The shortcoming of self-regulation to manage shale and tight gas production are magnified by

the unanswered questions about the treatment of hydraulic fracturing waste water, chemical

use and the liability for abandoned wells.860

853 Id at 8. 854 Simon Robb, ‘A best practice regulatory proposal for shale gas production’, 2014, pg 70 855 R S Khemani and DM Shapiro, ‘Glossary of Industrial Organisation Economics and Competition Law’

(Glossary, Organisation for Economic Co-Operation and Development, 1993) 73 at

<http://www.oecd.org/regreform/sectors/2376087.pdf> 856 Jennifer Nash, Assessing the Potential for Self-Regulation in the Shale Gas Industry, Harvard Kennedy

School, (accessed 16 April 2017) at

http://sites.nationalacademies.org/cs/groups/dbassesite/documents/webpage/dbasse_084362.pdf 857 Jillian Segal, Institutional self-regulation: what should be the role of the regulator?, (accessed 12 June 2017)

at http://download.asic.gov.au/media/1341128/NIGConf_081101.pdf 858 Matt Mace, Fracking Business as Usual, Analysis of the Failing EC Recommendations on Shale Gas, 2015,

pg 5 at <https://www.scribd.com/doc/284048822/Fracking-Business> 859 Id at 43. 860 Ibid.

129

Adaptive Management (AM) supports the communities’ perception of ecosystems and the

concerns they have with the environment.861 It involves managing plans, monitoring and

evaluating results and making adjustments according to what is learned.862 AM is based on the

idea that nature is dynamic and variable.863 As a result, it is difficult to predict the effect a

shale and tight gas project or regulatory regime will have on the environment before it is

applied.864

For AM to effectively inform complex environmental policy and decision-making,

stakeholders must ‘have the authority, means, and capacity to monitor and evaluate the

effectiveness of management and regulatory options once they are chosen… and they must

have a willingness and mechanism for adapting and revising options in the face of new

information’.865 Some commentators have suggested that AM is well suited to the challenges

associated with shale and tight gas production given decisions are made in the context of

‘significant uncertainty, limited scientific experience, and conflicting agendas of multiple

stakeholders’.866 The impacts of shale and tight gas extraction are minimised by applying

‘good regulation and adaptive management’.867 AM is based on agreement i.e., agreement as

to risks that should be incorporated using regulatory regimes.868

AM is reinforced by a preparedness to investigate regulatory options, the capacity to monitor

and evaluate the regulatory options once they are chosen, and a willingness to adapt regulatory

861 Jessica Lee, Theory to practice: Adaptive management of the groundwater impacts of Australian mining

projects, (2014) 31 EPLJ 251, 252 862 Williams B, “Adaptive Management of Natural Resources: Framework and Issues” (2011) 92 Journal of

Environmental Management 1346, 1347; Reever Morghan K, Sheley R and Svejcar T, ’Successful Adaptive

Management: The Integration of Research and Management’ (2006) 59(2) Rangeland Ecology & Management

216, 216-217; Gregory R, Ohlson D and Arvai J, ’Deconstructing Adaptive Management: Criteria for

Applications to Environmental Management’ (2006) 16(6) Ecological Applications 2411, 2412. 863 Jessica Lee, ‘Theory to practice: Adaptive management of the groundwater impacts of Australian mining

projects’ (2014) 31 EPLJ 251, 252 864 Thrower J, ’Adaptive Management and NEPA: How a Nonequilibrium View of Ecosystems Mandates

Flexible Regulation’ (2006) 33 Ecology Law Quarterly 871, 873. 865 Brian G. Rahm & Susan J. Riha ‘Evolving shale gas management: water resource

risks, impacts, and lessons learned’ (2014) 16 Environ. Sci.: Processes Impacts 1400, 1408 at

http://pubs.rsc.org/en/content/articlepdf/2014/EM/C4EM00018H 866 Adaptive Environmental Impact Assessment and Management, ed. C. Holling, John Wiley, London, 1978 867 Crawford School of Public Policy, Unconventional Gas Production and Water Resources, Lessons from the

United States on better governance – a workshop for Australian government officials, Australian National

University, July 2012, page 35 at https://crawford.anu.edu.au/pdf/inthenews/12186-unconventional-gas-

document-web-fa.PDF 868 Ibid.

130

regimes when new information is presented.869 AM is a coordinated, continual decision-

making process that can be used to deal with the environmental management challenges of

shale and tight gas operations given that decisions are made in circumstances where there is

significant uncertainty, reinforced by a limited scientific understanding of the impacts, and

divergent stakeholder views.870

AM involves the collection of baseline data and constant monitoring, to ensure that impacts

are detected and suitable action taken.871 Regulatory responses to potential risks ought to be

based on the possibility of risk, and where there is limited evidence to assess the possibility of

risk, adaptive management is a suitable approach.872 In terms of the water management, short

and long term is planning is paramount. AM involves monitoring, accounting and reporting of

water extraction, which informs water planning processes including allocation to meet

community needs and balancing economic development.873 The coal seam gas framework

contends that leading practices concerning water should include an AM framework.874

Some insist that in the United States the response to shale and tight gas does not reflect the

cautious, structured discourse and ‘process of continuous improvement’ that some argue is

needed, and which is the trademark of AM.875 AM has the potential to decrease resistance to

shale and tight gas production given it assists in the determining of risk, reinforcing support

for research, assessment and planning, providing a basis for funding significant features of

governance before shale and tight gas activities begins., i.e. hydraulic fracturing, and reducing

resistance to adaptive management policy-making that strives to link contemporary science

with economic, social, and value considerations.876

869 Brian G. Rahm & Susan J. Riha ‘Evolving shale gas management: water resource

risks, impacts, and lessons learned’ (2014) 16 Environ. Sci.: Processes Impacts 1400, 1408 at

http://pubs.rsc.org/en/content/articlepdf/2014/EM/C4EM00018H 870 Id at 1401. 871 The National Harmonised Regulatory Framework for Coal Seam Gas, 2013, pg 14 at

http://scer.govspace.gov.au/files/2013/06/National-Harmonised-Regulatory-Framework-for-Natural-Gas-from-

Coal-Seams.pdf 872 Ibid. 873 Id at 40. 874 Ibid. 875 Brian G. Rahm & Susan J. Riha ‘Evolving shale gas management: water resource

risks, impacts, and lessons learned’ (2014) 16 Environ. Sci.: Processes Impacts 1400, 1408 at

http://pubs.rsc.org/en/content/articlepdf/2014/EM/C4EM00018H 876 Id at 1410.

131

Although AM is an effective regulatory approach, the risks associated with hydraulic fracturing

require a more ‘robust, transparent and independent assessment process’ which would reduce

the likelihood of groundwater contamination.877 While stakeholders continue to study the

impacts of hydraulic fracturing, the question of whether to adhere to the precautionary principle

in management decisions has emerged.878 The exploitation of shale and tight gas generates a

considerable risk of contamination, both to ground and surface water, and it is reasonable to

contend that a precautionary approach should be used until an evidence base is developed.879

There is a significant amount of unreliable evidence from the United States that contamination

has arisen in a number of cases involving the extraction of shale and tight gas.880 The evidence

of contamination and the application of the precautionary principle in the European Union, has

led to calls in the United Kingdom for a delay in shale and tight gas extraction until clear

evidence of its safety can be offered.881 The precautionary principle is used in various

international treaties and declarations, as well as Australian Federal and state laws though there

is no generally accepted definition of the precautionary principle.882

The precautionary principle, if used correctly, can guarantee that community concerns are

addressed.883 This approach has a procedural emphasis on community participation and

transparency.884 The transparency component is extremely important given the public concern

about shale and tight gas.885 Concerns with shale and tight gas production can be alleviated by

transparency, i.e., operational transparency (extraction/production), and how legislators make

877 Karen Bubna-Litic, Fracking in Australia: The future in SA? (2015) 32 EPLJ 437, 447 878 Barth, E, Hydraulic Fracturing “cheat sheet” for Peer-reviewed Literature, 2012 at

https://environment.yale.edu/yer/article/hydraulic-fracturing-cheat-sheet 879 Wood, R., Shale gas: a provisional assessment of climate change and environmental impacts, 2011, pg 5 at <

https://www.research.manchester.ac.uk/portal/files/36728313/FULL_TEXT.PDF> 880 Ibid. 881 Id at 76, 77. 882 United Kingdom Interdepartmental Liaison Group on Risk Assessment (UK-ILGRA), The Precautionary

Principle: Policy and Application, (accessed 26 September 2017) at

http://www.hse.gov.uk/aboutus/meetings/committees/ilgra/pppa.htm#FOOTNOTE 883 Elizabeth E. Bomberg, Shale Governance in the European Union: Principles and Practice, 2014, pg 8 at

http://closup.umich.edu/files/ieep-2014-shale-governance-in-the-eu.pdf 884 European Commission. (2 February 2000). Communication from the Commission of 2 February 2000 on the

precautionary principle [COM(2000) 1 final]. Brussels: European Commission. 885 International Energy Agency (IEA). (2012). Golden rules for a golden age of gas. Special Report on

Unconventional Gas. Paris: IEA. Retrieved from

http://www.worldenergyoutlook.org/media/weowebsite/2012/goldenrules/WEO2012_GoldenRulesReport.pdf

; see also Stevens, P. (2012). The shale gas revolution: Developments and changes. Briefing Paper. London:

Chatham House.

132

decisions about regulation.886 The precautionary principle’s transparency component affects a

number of key shale policies in the European Union, for example, environmental impact

assessments, chemical disclosure and the development of regulation.887 Transparency is one

of the central tenets behind the European Union’s environmental impact assessment rules that

are meant to permit ‘transparent and democratic participation in the decision whether to allow

such activities to proceed’.888

Some industry commentators argue that the precautionary principle or the ‘better safe than

sorry’889 approach to shale and tight gas inhibits the use of new technology until risks are better

understood.890 Although the precautionary principle is used in the European Union and gained

popularity in the United States, it has been rejected by some regulatory academics.891 The

precautionary principle is generally used to regulate catastrophic risks,892 i.e., nuclear power,

genetically modified organisms, human cloning, and climate change.893 The harm caused is

likely to be permanent with a considerable number of individuals impacted.894 By comparison,

hydraulic fracturing poses risks to individual aquifers.895 Those that oppose the use of the

precautionary principle for shale and tight gas accept that hydraulic fracturing can devastate an

aquifer’s value as a drinking source or for agricultural purposes, and as hydraulic fracturing

886 Elizabeth E. Bomberg., Shale Governance in the European Union: Principles and Practice, 2014, pg 8 at

http://closup.umich.edu/files/ieep-2014-shale-governance-in-the-eu.pdf 887 Ibid. 888 Francioni, F. & Bakker, C. (January 2013). The evolution of the global environmental system: Trends and

prospects. Transworld Working Paper. Brussels: Transworld. Retrieved from <http://www.transworld-

fp7.eu/?p=985> 889 Frank B. Cross, Paradoxical Perils of the Precautionary Principle, (1996) 53 Wash. & Lee L. Rev. 851, 851 890 See generally European Risk Forum, The Precautionary Principle: Application and Way Forward, 18–20,

2011 (defining and discussing the precautionary principle’s origins) 891 See, e.g., Cass R. Sunstein, Laws of Fear: Beyond the Precautionary Principle (Cambridge) (2005)

(discussing various mechanisms that enable a fearful public to invoke the precautionary principle, which yields

unjustified intrusions upon civil liberties). 892 See Frederick Schauer, ‘Is it Better to Be Safe than Sorry?: Free Speech and the Precautionary Principle’

(2009) 36 Pepp. L. Rev. 301, 304–06 893 Thomas W. Merrill & David M. Schizer, ‘The Shale Oil and Gas Revolution, Hydraulic Fracturing, and

Water Contamination: A Regulatory Strategy’ (2013) Minnesota Law Review 205 894 Ibid. 895 Spence D, ‘Fracking Regulations: Is Federal Hydraulic Fracturing Regulation Around the Corner? (accessed

17 June 2017) at <

https://www.mccombs.utexas.edu/~/media/Files/MSB/Centers/EMIC/EMIC%20Misc/Fracking-Regulations-

Is-Federal-Hydraulic-Fracturing-Regulation-Around-Corner.PDF>

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becomes more common, more aquifers are put at risk.896 The contention is that alternative

sources of water are available at a cost to consumers and contaminated water can be treated.897

To use the precautionary principle for shale and tight gas extraction disregards the years of

experience operators have with hydraulic fracturing. Operators have performed over two

million fractures in the United States.898 The evidence indicates that the risk of widespread or

total destruction to water resources is remote,899 and the likelihood of local contamination is

manageable providing hydraulic fracturing is done correctly.900 Those that support the

precautionary principle insist that in the absence of scientific agreement about the potential

harm from hydraulic fracturing, the onus to prove that it is safe lies with the industry.901 In the

absence of evidence that hydraulic fracturing is safe, precautions such as ceasing ongoing

mining activities should be taken to protect the environment.902

3.7 Conclusion

This chapter provided a brief history of mineral and petroleum ownership which included an

examination of indigenous rights. The chapter examined regulatory approvals focusing on

environmental approvals and assessment. It also examined the various regulatory approaches

that can be used to manage the exploitation of shale and tight gas.

Modern regulatory approaches are the alternative to prescriptive regulation, though it is likely

other approaches are more suitable for managing the risks of shale gas and tight gas extraction.

896 Thomas W. Merrill & David M. Schizer, ‘The Shale Oil and Gas Revolution, Hydraulic Fracturing, and

Water Contamination: A Regulatory Strategy’ (2013) Minnesota Law Review 205 897 See EPA, Ground Water Cleanup at Superfund Sites, December 1996

at<http://www.epa.gov/superfund/health/conmedia/gwdocs/brochure.htm> (explaining that ground water can

be treated by pumping it to the surface, decontaminating it, and then discharging it back into the ground or into

a stream or river). 898 Thomas W. Merrill & David M. Schizer, ‘The Shale Oil and Gas Revolution, Hydraulic Fracturing, and

Water Contamination: A Regulatory Strategy’ (2013) Minnesota Law Review 205 899 Spence D, ‘Fracking Regulations: Is Federal Hydraulic Fracturing Regulation Around the Corner? (accessed

17 June 2017) at <

https://www.mccombs.utexas.edu/~/media/Files/MSB/Centers/EMIC/EMIC%20Misc/Fracking-Regulations-

Is-Federal-Hydraulic-Fracturing-Regulation-Around-Corner.PDF>

901 Barth, E, Hydraulic Fracturing “cheat sheet” for Peer-reviewed Literature, 2012 at

https://environment.yale.edu/yer/article/hydraulic-fracturing-cheat-sheet 902 Ibid.

134

These modern approaches have simply adjusted the state’s role by using non-government

participation in encouraging regulatory compliance. Stakeholders must determine what

approach or approaches might best address the different regulatory tasks likely to confront

operators. The different circumstances between states does not justify regulating more or less

rigorously.

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4 COMPARATIVE ANALYSIS OF REGULATORY ISSUES

The social and environmental risks and challenges linked to the exploitation of shale and tight

gas primarily relate to land access, water access and quality protection, the regulation of well

technology for drilling and hydraulic fracturing and decommissioning and associated issues

(abandonment, rehabilitation and reclamation). These and other issues have been examined in

parliamentary inquiries in Western Australia and South Australia.903

It is highly likely that community and political antagonism toward shale and tight gas

exploitation will continue unless satisfactory regulatory alternatives are developed. There are

a number of international studies that have examined the risks and challenges associated with

exploiting shale and tight gas, though the author argues that none have dealt in a meaningful

way with the specific shortcomings and regulatory gaps that this thesis contends exist in

Western Australia and South Australia.

In the author’s opinion, Western Australia and South Australia’s regulatory regimes are under-

analysed and there are limited academic studies on the particular issues outlined in this thesis’

introductory chapter (and above). Given that shale and tight gas exploitation is in its infancy

in both jurisdictions, understanding all of the relevant risks and challenges is difficult.904

This chapter will compare land access, which includes statutory access and access agreement

regimes, water quality and protection issues, which includes examining the various state based

water legislation, drilling and fracturing, which includes flow-back, produced and recycled

water and well and field management. The chapter will also examine decommissioning and

rehabilitation.

903 The Standing Committee on Environment and Public Affairs, Parliament of Western Australia, Inquiry into

the Implications for Western Australia of Hydraulic Fracturing for Unconventional Gas, (2015) 904 Brian G. Rahm& Susan J. Riha ‘Evolving shale gas management: water resource

risks, impacts, and lessons learned’ (2014) 16 Environ. Sci.: Processes Impacts 1400, 1408 at

http://pubs.rsc.org/en/content/articlepdf/2014/EM/C4EM00018H

136

4.1 Land Access

Western Australia, South Australia and Colorado all use non-statutory access agreements to

manage the relationship between operators and landowners when operators seek to exploit

shale and tight gas. The South Australia government maintains that ‘mutual trust for

compatible, sustainable land access for upstream petroleum are traditionally indemnified with

formal land access agreements struck between operators, potentially affected people and

enterprise.’905 Western Australia’s Standing Committee on Environment and Public Affairs

recommended that the State government ‘draft legislation for a statutory framework for land

access agreements between land owners and resource companies’.906 As a result, the Western

Australian government established a land access working group to review the need for a

statutory framework for land access.907

Western Australia’s peak industry groups for agriculture and oil have published guidelines

to assist operators and landowners to reach fair and equitable agreements.908 DMIRS

expects, but does not insist, that ‘title holders engage early and often with all stakeholders

including private land holders, lessees, shires and members of the community’.909 The

Standing Committee on Environment and Public Affairs identified a number of

deficiencies in Western Australia’s land access regime and asked the State government to

consider drafting legislation for a statutory framework for land access agreements.910

905 Energy Resources Division, Department of Manufacturing, Innovation, Trade, Resources and Energy,

Roadmap for Unconventional Gas Projects in South Australia, 2012, pg 147 at <

https://statedevelopment.sa.gov.au/upload/mineral-and-energy-

resources/Roadmap_Unconventional_Gas_Projects_SA_12-12-12.pdf> 906 The Standing Committee on Environment and Public Affairs, Parliament of Western Australia, Inquiry into

the Implications for Western Australia of Hydraulic Fracturing for Unconventional Gas, November 2015,

Chapter 5, pg 75 907 Land Access Working Group established, Thursday 15 September 2016 at

https://www.mediastatements.wa.gov.au/Pages/Barnett/2016/09/Land-Access-Working-Group-established.aspx 908WA Farmers, PGA, APPEA, Vegetables WA, Farming Land Access Agreement Template for Petroleum

Activities under the Petroleum and Geothermal Energy Resources Act 1967, October 2015 at

http://www.appea.com.au/wp-content/uploads/2015/10/Final-Template-Access-Agreement-Oct-2015.pdf 909 Department of Mines, Industry Regulation and Safety, Land use and access, (accessed 2 January 2018), at

http://www.dmp.wa.gov.au/Petroleum/Land-use-and-access-20009.aspx 910 The Standing Committee on Environment and Public Affairs, Parliament of Western Australia, Inquiry into

the Implications for Western Australia of Hydraulic Fracturing for Unconventional Gas, November 2015,

Chapter 5, pg 75

137

Both Western Australia and South Australia’s land access regimes exhibit historic efforts to

mediate the interests of the state, as resource owner with the rights and interests of landholders

(particularly agricultural landholders) and operators.911 Both appear relatively comfortable

with the use of access agreements. Access agreements are also used in in Colorado and are

known as surface use agreement. The agreements are private contracts between operators and

landowners.

South Australia’s Natural Resources Committee argued that landowners should be supported

when they negotiate with operators to ensure that conduct and compensation agreements are

developed in a harmonious way and are mutually beneficial.912 Further, the Committee felt

that ‘unfair or hastily derived compensation agreements are likely to set poor precedents and

precipitate long-term damage to working relationship between petroleum and geothermal

energy explorers and the community’.913 The stand out provision in the OGCA is the reasonable

accommodation provision.914 The provision requires operators to disturb only the amount of

land that is "reasonable and necessary" to extract gas.915

4.1.1 Statutory Access – Western Australia and South Australia

In Western Australia, operators cannot enter private land that is less than 2000 square metres,

where it has been used as a cemetery or burial place or is within 150 metres of a cemetery,

burial place, reservoir or any substantial improvement without written consent.916 Regulated

activities cannot be undertaken in Western Australia unless a compensation agreement has been

executed or an agreement reached with a landowner or occupier.917

911 Department of Mines and Petroleum, Government of Western Australia, Land Access Information Paper,

15 February 2017, pg 3 912 Inquiry into Unconventional Gas (Fracking) in the South East of South Australia, Final Report, One

Hundred Nineteenth Report of the Natural Resources Committee, Tabled in the House of Assembly and

ordered to be published 29 November 2016, p 12 at

<https://www.parliament.sa.gov.au/Committees/Pages/Committees.aspx?CTId=5&CId=295> 913 Department of the Premier and Cabinet, Liaison guidelines for landowners and petroleum and geothermal

energy explorers in South Australia, November 2014, pg 7, Petroleum and Geothermal Regulatory Guidelines

005 https://sarigbasis.pir.sa.gov.au/WebtopEw/ws/samref/sarig1/image/DDD/PGRG005.pdf 914 Section 34-60-127 of the OGC Act at <http://www.lexisnexis.com/hottopics/Colorado/> 915 Section 34-60-127 of the OGC Act at <http://www.lexisnexis.com/hottopics/Colorado/> 916 Petroleum and Geothermal Energy Resources Act 1967 (WA),s 16 917 Petroleum and Geothermal Energy Resources Act 1967 (WA), s 20

138

Compensation is payable when operators deprive landowners of possession of their land, for

damage to land, for damage to improvements they have made, for land separation (gas

producing land from other land), for severance of rights-of-way and for consequential

damages.918 Land separation is quite a significant issue for farmers.919 If operators and

landowners fail to agree to an amount of compensation offered, either party can apply to the

Magistrates Court to have an amount of compensation fixed.920

In South Australia, operators must provide written notice to landowners at least 21 days prior

to entry.921 They must notify a landowner of their intention to enter the land and, if they

propose to carry out regulated activities, the nature of the activities.922 Operators must describe

the proposed activities, where they will be carried out, the duration, any associated

consequences, actions to manage and address the consequences, the impact or potential impact

of the activities on the land, whether the owner may object to entry and provide reasonable

information on the rights of an owner to claim compensation.923

Landowners can object to an operator entering their land within 14 days of the operator’s notice

of intended entry.924 An operator must notify the Minister if they receive a notice of objection

from a landowner disputing entry.925 Both parties can apply to the Warden's Court for a

resolution of the dispute.926 The Warden's Court can determine terms on which the licensee

may enter the land and carry out regulated activities on the land.927

Any compensation a landowner receives must be connected to the them as the landowner and

not a third party and cover their deprivation or impairment of the use and enjoyment, damage

(not including damage that has been addressed by the operator), damage to, or disturbance of,

any business or other activity lawfully conducted on the land, and for consequential loss

918 Petroleum and Geothermal Energy Resources Act 1967 (WA), s 17(2) 919 Environment and Communications Legislation Committee (Cth), Inquiry into the Landholders’ Right to

Refuse (Gas and Coal) Bill 2015, pg 13-14 920 Petroleum and Geothermal Energy Resources Act 1967 (WA), s17(4) 921 Petroleum and Geothermal Energy Act 2000 (SA), s 61 922 Petroleum and Geothermal Energy Act 2000 (SA), s 61(b) 923 Petroleum and Geothermal Energy Regulations 2013 (SA), r 22 924 Petroleum and Geothermal Energy Act 2000 (SA), s 62(2) 925 Petroleum and Geothermal Energy Act 2000 (SA), s 62(3) 926 Petroleum and Geothermal Energy Act 2000 (SA), s 62(5) 927 Petroleum and Geothermal Energy Act 2000 (SA), s 62(6)

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suffered or incurred by the landowner as a result of the operator entering the land and carrying

out regulated activities.928

Compensation is not payable for value or possible value of the regulated resource contained in

the land.929 The compensation may consist of an additional amount incurred by a landowner

in connection with any negotiation or dispute related to the operator gaining access to the land

and the activities to be carried out on the land and the compensation to be paid.930

If the activities of an operator significantly impair the landowner's use and enjoyment of the

land, a landowner may apply to the relevant court for an order that the operator acquire the

land.931 The court may make an order transferring the land to the operator, order the operator

to pay to the owner an amount equal to the market value of the land and a further amount the

court considers just by way of compensation for disturbance.932 The compensation

provisions are essentially an 'umbrella' that sits over the negotiations. The author favours a

statutory provision that ensures that landowners are involved in discussions.

4.1.2 Statutory Access – Colorado

Some industry commentators argue that Colorado has a vested interest in protecting mineral

rights.933 Colorado's land board is responsible for three million acres of land and four million

acres of mineral rights that were ceded to the State from the Federal government at the time of

statehood.934 As a result of split estate issues, the State's mineral property can be underneath

private or municipal owned surface land.935

The reasonable accommodation provision is a proactive attempt by Colorado to manage the

interests of operators and landowners in the exploitation of shale and tight gas. Even the use

928 Petroleum and Geothermal Energy Act 2000 (SA), s 63(2) 929 Petroleum and Geothermal Energy Act 2000 (SA), s 63(3) 930 Petroleum and Geothermal Energy Act 2000 (SA), s 63(3a) 931 Petroleum and Geothermal Energy Act 2000 (SA), s 64(1) 932 Petroleum and Geothermal Energy Act 2000 (SA), s 64(2) 933 Stacia S. Ryder and Peter M. Hall, ‘This land is your land, maybe: A historical institutionalist analysis for

contextualizing split estate conflicts in U.S unconventional oil and gas development’(2017) 63 Land Use

Policy 149-159, 156 934 Ibid. 935 Ibid.

140

of the word 'reasonable' is more palatable than ‘compensation’ which is typically linked to

money awarded to someone in recognition of loss, suffering or injury. The provision deals

with reasonable use and accommodation, sanctions compensatory damages and equitable relief

and does not impinge common law tort actions or contract rights.936

One industry commentator argues that the issue with split estates was dealt with as part of an

overhaul of Colorado’s oil and gas regulations in 2007, which codified the accommodation

doctrine rooted in Gerrity Oil and Gas Corp. v. Magness 923 P.2d 261 (1995).937 The laws

extended surface rights to compel operators to consider surface rights of owners, minimise

surface use and damage, use alternative means (if they are available) to mitigate surface

intrusion and bear the burden of proof if a lawsuit is filed as a result of their failure to minimise

intrusion.938

Some industry commentators insist that the law clarified the legal situation between mineral

and surface owners, suggesting that it was in the public’s interest, ‘as substantial increases in

the amount of oil and gas operations and the number of rural residents (were resulting) in

numerous conflicts between surface owners and oil and gas operators’.939 Colorado operations

must be conducted in a way that assists surface owners and minimises intrusion upon and

damage to surface lands.940 This is achieved by ‘selecting alternative locations for wells, roads,

pipelines, or production facilities, or employing alternative means of operation, that prevent,

reduce, or mitigate the impacts of the oil and gas operations on the surface where such

alternatives are technologically sound, economically practicable, and reasonably available to

the operator’.941

If an operator fails to meet the requirements set out in the reasonable accommodation provision,

a surface owner may seek compensatory damages or such equitable relief.942 If litigation

936 Reasonable Accommodation, Colo. Rev. Stat §34-60-127 937 Stacia S. Ryder and Peter M. Hall, ‘This land is your land, maybe: A historical institutionalist analysis for

contextualizing split estate conflicts in U.S unconventional oil and gas development’(2017) 63 Land Use

Policy 149-159, 155 938 Ibid. 939 Ibid. 940 Section 34-60-127 of the OGC Act at <http://www.lexisnexis.com/hottopics/Colorado/>

941Section 34-60-127(1)(b) of the OGC Act at http://www.lexisnexis.com/hottopics/Colorado/ 942 Section 34-60-127(2) of the OGC Act at http://www.lexisnexis.com/hottopics/Colorado/

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occurs, a surface owner can present evidence that the operator's use of the surface substantially

affected the surface owner's use of the surface of the land.943 An operator must show that it met

the standard set out in the provision.944 As an affirmative defence, an operator may argue that

it has conducted its operations in accordance with a regulatory obligation, contractual

obligation, or land use plan that is specifically applicable to the alleged intrusion or damage.945

The standard of conduct set out in the reasonable accommodation provision does not preclude

an operator from entering private property and using the surface as is reasonable and necessary

to explore for, develop, and produce oil and gas.946 The accommodation doctrine was first

recognised by the Texas Supreme Court in Getty Oil Company v. Jones, 470 S.W.2d (618

(Tex.1971). Some industry commentators suggest that it served to readjust the position

between mineral and surface estates back toward the equilibrium.947 The issue in Getty was

the height of oil pumps installed by Getty Oil. Jones argued that the oil pumps interfered with

the sprinkler system he used to irrigate his property, and as a result much of his land could not

be used to grow crops.948 Jones asked Getty Oil to either install other pumps or dig “cellars”

to lower the height of the pumps. Evidence was provided to the court that indicated that neither

option would be very expensive or would impact production.

The Supreme Court held that ‘Getty Oil had to ‘reasonably accommodate’ Jones’ use of the

surface’.949 The court held that a mineral owner may be compelled to accommodate a surface

owner when there is an existing surface use, the mineral owner’s use of the surface impedes or

damages the existing use of the surface and under recognised industry practices, there are other

options available to recover the minerals.950

Some industry commentators argue that although Colorado’s reasonable accommodation

provision ‘is sparse and not well defined…the COGCC, has numerous regulations that speak

943 Section 34-60-127(3)(a) of the OGC Act at <http://www.lexisnexis.com/hottopics/Colorado/> 944 Ibid 945 Section 34-60-127(3)(b) of the OGC Act at <http://www.lexisnexis.com/hottopics/Colorado/> 946 Section 34-60-127(1)(c) of the OGC Act at <http://www.lexisnexis.com/hottopics/Colorado/> 947 Robert J Burnett, ‘The Accommodation Doctrine: Balancing the Interests of the Surface Owner and the

Mineral Owner’, Houston Harbaugh, Attorneys at Law, (accessed 12 April 2018) at < https://www.hh-

law.com/the-accommodation-doctrine-balancing-the-interests-of-the-surface-owner-and-the-mineral-owner/> 948 Getty Oil, 470 S.W.2d at 620 949 Getty Oil, 470 S.W.2d at 621 950 Getty Oil, 470 S.W.2d at 622

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on the issue...this makes the COGCC’s administrative procedure unusually relevant to surface

owners seeking surface use agreements, contract enforcement, damages, or other remedies’.951

Some industry commentators have criticised the accommodation doctrine on the grounds that

it creates doubt because courts have been left to question the practicality of the business

judgement of operators.952 Some industry commentators argue that the accommodation

doctrine can fail to take into account the increased risks associated with alternatives, such as

directional drilling.953

The PGERA and PGEA should include a reasonable accommodation provision that requires

operators to conduct their activities in a way that assists surface owners and minimises intrusion

upon and damage to surface lands. This can be easily achieved by operators and landowners

choosing different locations for wells, roads, pipelines, or production facilities, or using

alternative means of operation, that prevent, reduce, or mitigate the impacts of the oil and gas

operations on the surface where such alternatives are technologically sound, economically

practicable, and reasonably available to the operator.

4.1.3 Land access agreements – Western Australia and South Australia

In Western Australia, a land access agreement template954, explanation document955 and

farmer’s guide assists farmers and operators when they are negotiating land access for the

purpose of exploiting shale and tight gas.956 The guide states that the first question landowners

should ask operators when they are approached is ‘what are your plans and when do you think

work will start?’957 The guide urges farmers to coordinate with their neighbours if they will

951 Catherine Toan, Esq, Split Estates, Colorado Environmental Law Ltd, (accessed 16 June 2017) at

http://www.oilandgasbmps.org/docs/GEN324_split%20estates.pdf 952 Jeanine Feriancek & Cynthia L. McNeil, ‘Oil Company Surface Use: Do Farmers Need Protection?’ (1995)

Winter 28 Nat. Resources and Env’t 31 953 Ibid. 954 WA Farmers, PGA, APPEA, Vegetables WA, Farming Land Access Agreement Template for Petroleum

Activities under the Petroleum and Geothermal Energy Resources Act 1967, October 2015 at

http://www.appea.com.au/wp-content/uploads/2015/10/Final-Template-Access-Agreement-Oct-2015.pdf 955 WA Farmers, PGA, APPEA, Vegetables WA, Explanation of the Land Access Agreement Template for

Petroleum Activities under the Petroleum and Geothermal Energy Resources Act 1967, October 2015 at

https://www.appea.com.au/wp-content/uploads/2015/10/Final-Land-Access-Template-Explanation-Oct-

2015.pdf 956 WA Farmers, PGA, APPEA, Vegetables WA, A Farmer’s guide to Land Access for Petroleum Activities

under the Petroleum and Geothermal Energy Resources Act 1967, October 2015 at

https://www.appea.com.au/wp-content/uploads/2015/10/Final-Farmers-Guide-to-Land-Access-Oct-2015.pdf 957 Id at 3.

143

also be affected by the same operation, obtain independent legal advice and educate themselves

about environmental monitoring and regulation.958 The guide was drafted to deal only with the

exploration phase of shale and tight gas development and it points out that a proposal for field

development and commercial production must be dealt with under a separate agreement.959

The guide asks farmers to consider how exploration activities can deliver long term

improvements to farms, pointing out that exploration activity can involve operators building

infrastructure like roads, water bores, fencing and power supply.960 It goes further and indicates

that, in certain cases, infrastructure can be retained and used by farmers and that, in some cases,

operators may even hire farmers to carry out rehabilitation work pending approval from

regulators.961 A model agreement was developed to assist with negotiations.962 The aim of the

agreement is to deliver fairness and equity to negotiating parties when they are discussing

access and compensation.963

According to the guide the most important elements of a model agreement are that operators

minimise disturbance to farming assets and operations, that farmers allow exploration to

proceed without unnecessary disruption once an agreement has been reached, that there is prior

communication on operational activities, locations, equipment use, fire management and other

relevant information, that operators are aware of their obligations to cover reasonable costs,

including proposals for legal and financial advice, other costs directly related to preparing the

agreement, and technical advice is provided on the impacts of petroleum exploration.964

South Australia’s liaison guidelines set out that operators should establish good relationships

with landowners so as to facilitate, amongst other things, arrangements regarding infrastructure

(e.g water sources, roads, tracks, fences, gates), the meeting of regulatory requirements and

to facilitate negotiating fair compensation.965

958 Ibid. 959 Id at 2. 960 Ibid. 961 Ibid. 962 Id at 5. 963 Ibid. 964 Id at 7. 965 Department of State Development, (SA), Liaison guidelines for landowners and petroleum and geothermal

energy explorers in SA, Petroleum and Geothermal Regulatory Guidelines 005, Version 1.1, November 2014,

pg 4

144

The liaison guidelines explicitly set out that operators are expected, amongst other things, to

avoid damage to improvements and manage activities whilst considering their effects on

vegetation and soil, avoid interfering with crops, livestock and other economic activities on the

property, avoid disturbance to dwellings and pay compensation promptly.966 The guidelines

specify that a landowner’s contribution is to provide adequate contact details, respond to

requests for information issued under the PGEA and advise operators of any changes to stock

and management programs.967 The South Australian guidelines stipulate that landowners

should be provided with, amongst other things, details of proposed activities, including, the

proposed location of fieldwork, the extent and type of the operations to be conducted and

proposed techniques or options that address any landowner concerns.968

The author does not favour the use of land access agreements to manage the

operator/landowner relationship in the absence of a statutory foundation. Neither does the

author favour the compensation provision contained within the PGERA and PGEA. Land

access agreements in Western Australia are private agreements to which DMIRS is not a

party.969 This is also the case in South Australia. As has been publicly stated by DMIRS,

‘PGERA land access agreements are private negotiations…DMP is not a party to the

arrangements or their negotiation’.970 DMIRS is also on record stating that access agreements

can be used to ‘determine which areas of land can be accessed and how often, which entrance

and access tracks vehicles are permitted to use and the land owner’s preferred method of

communication’.971

A good faith clause should be inserted into the PGERA and PGEA similar to the one contained

in the COGCC rules.972 The COGCC requires operators to meet in ‘good faith’ with

landowners to negotiate surface use agreements. These meetings deal with the location of

966 Ibid. 967 Ibid. 968 Id at 6. 969 Department of Mines, Industry Regulation and Safety, Land Access Information Paper, 15 February 2017,

pg 7 at http://www.dmp.wa.gov.au/Documents/About-Us-Careers/Land_Access_Information_Paper.pdf 970 Ibid. 971 Department of Mines, Industry Regulation and Safety, Land use and access, (accessed 15 June 2017) at

http://www.dmp.wa.gov.au/Petroleum/Land-use-and-access-20009.aspx 972 Colorado Oil & Gas Conservation Commission, Department of Natural Resources, Information for Surface

Owners, (accessed 18 June 2017) at

https://cogcc.state.co.us/documents/about/Help/Surface%20Owners%20Brochure.pdf

145

roads, production facilities, well sites, other oil and gas operations and reclamation and

abandonment.973 Meetings should occur at an agreed time and before the use of heavy

equipment.974 The COGCC rules explicitly provide landowners and occupiers with the

opportunity to provide feedback on favoured locations for wells and associated production

facilities, the timing of oil and gas operations, and mitigation measures or best management

practices to be used during operations.975 The PGEA regulations stipulate that operators must

advise and confer with landowners and provide adequate information to assist them in making

informed decisions about the impact or possible impact of the proposed operation.

4.1.4 Surface use agreements - Colorado

Surface use agreements are private contracts that deal with an operator’s activities on the

surface owner’s property.976 The COGCC has no authority over terms of a surface use

agreement.977 The landowner’s guide encourages the drafting of protective leases in

surface use agreements.978 The Colorado guide advocates for the inclusion of a primary

term of a standard lease (typically 3-5 years).979 During this time operators must drill a

well and, if they fail to do so, their lease expires. The secondary term continues as long

as the wells on the property are producing gas.980 The Colorado guide encourages

landowners to include a pugh clause in leases so that land not in production can split from

acreage in production.981 This protects landowners from the irregularity of having their

entire property held under a lease by production from a very small portion.982 When the

primary term of a lease ends, only the land being developed is held into the secondary

973 Rule 306 of the COGCC rules at https://cogcc.state.co.us/documents/reg/Rules/LATEST/300Series.pdf 974 Rule 306(a) of the COGCC rules at https://cogcc.state.co.us/documents/reg/Rules/LATEST/300Series.pdf 975 COGGC rules, Series drilling, development, production and abandonment, (accessed 18 June 2017) at

https://cogcc.state.co.us/documents/reg/Rules/LATEST/300Series.pdf 976 Colorado Oil & Gas Conservation Commission, Department of Natural Resources, Information for Surface

Owners, (accessed 17 June 2017) at

https://cogcc.state.co.us/documents/about/Help/Surface%20Owners%20Brochure.pdf 977 Ibid. 978 Matt Sura, Colorado Landowner’s Guide to Oil and Gas Development, (accessed 15 May 2017) at

http://www.oilandgasbmps.org/landowners-guide/ 979 Ibid. 980 Matt Sura, A Protective Lease, Colorado Landowner’s Guide to Oil and Gas Development,(accessed 18

May 2017) at http://www.oilandgasbmps.org/landowners-guide/ 981 US Legal, Pugh Clause Law and Legal Definition at < https://definitions.uslegal.com/p/pugh-clause/>

982 Roseberry v. Louisiana Land & Exploration Co., 470 So. 2d 178 (La. Ct. App. 1985)

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term.983 Non-producing land can be re-leased to the same operator or leased to another

operator.984

A standard industry lease gives an operator the right to, ‘unimpeded ingress and access to

the leased lands’, and the ‘right to use so much of the surface, and at such locations, as

may be necessary or convenient for lessee's oil and gas operations.’985 Under a standard

industry lease, the operator may use as much of the landowner’s surface as they wish.986

The Colorado guide encourages landowners to include certain items in a surface use

agreement as part of their lease.987

Operators in Colorado are normally willing to enter into surface use agreements in order

to gain timely and trouble free access and use of the surface.988 Where there is no split

estate, the lease with the fee owner will regularly include surface damage provisions, with

itemised payments and provisions that restrict surface use to what is needed, specifying

the size of the site, identifying the locations and width of access roads and rights of way,

and demanding fencing.989 Where an operator is unable or unwilling to negotiate a surface

use agreement when a lease is signed, a provision can be added that states, ‘any entry or

location of facilities on the surface property is forbidden without permission granted

through a separate surface use agreement.’990

The Colorado guide urges landowners to ensure surface use agreements indicate the

location of wells given that directional or horizontally drilled wells allow for well pads to

be placed some distance away from gas deposits.991 It encourages landowners to discuss

the location of wells with operators and, where wells must to be located on a landowner’s

983 Matt Sura, A Protective Lease, Colorado Landowner’s Guide to Oil and Gas Development, (accessed 17

June 2017) at http://www.oilandgasbmps.org/landowners-guide/ 984 Ibid. 985 Ibid. 986 Ibid. 987 Ibid. 988 Kendor P. Jones, John F. (Jeff) Welborn, Chelsey J. Russell ‘Split Estates and Surface Access Issues’

Landman’s Legal Handbook Chapter 9 (Rocky Mt. Min. L. FDN., 5th ed., 2013), pg 193 989 Ibid. 990 Matt Sura, A Protective Lease, Colorado Landowner’s Guide to Oil and Gas Development, (accessed 18

June 2017) at http://www.oilandgasbmps.org/landowners-guide/ 991 Matt Sura, Location of the well(s), Colorado Landowner’s Guide to Oil and Gas Development, Part VI –

Negotiating with the Oil and Gas Industry, C. Surface Use Agreement, (accessed 17 June 2017) at

http://www.oilandgasbmps.org/landowners-guide/#7

147

property, consideration should be given to truck traffic, noise, and odours from gas

facilities.992 Surface use agreements should state whether operators intend to use multi-

well pads, i.e., whether they intend to co-locate wells on single well pads to minimise

surface impacts.993 The co-location of wells can result in much larger facilities, the

generation of more air emissions, noise, traffic, light, result in longer drilling times and

should be located away from homes.994

Landowners in Colorado are encouraged to negotiate the location of roads and vehicle

access, in particular whether there is an intention to construct temporary roads or whether

they will be built to specific standards.995 The guide suggests that consideration should

be given to drilling wells near existing roads.996

Landowners are encouraged to negotiate transportation plans with operators.997

Agreements should outline the frequency of an operator’s entry to a landowner’s

property.998 According to the guide, it can take 2,000 round trip truck trips to drill a

well.999 After a well is drilled, consideration should be given to the frequency of

monitoring.1000 Landowners should establish whether they will consent to extra gas

facilities (such as processing facilities, compressor engines, or temporary worker housing)

being located on their property. Surface use agreements should deal with the issue of

additional equipment and facilities.1001

992 Ibid. 993 Matt Sura, Multi-well pads, Colorado Landowner’s Guide to Oil and Gas Development, Part VI –

Negotiating with the Oil and Gas Industry, C. Surface Use Agreement, (17 June 2017) at

http://www.oilandgasbmps.org/landowners-guide/#7 994 Ibid. 995 Matt Sura, Location of roads and vehicle access, Colorado Landowner’s Guide to Oil and Gas

Development, Part VI – Negotiating with the Oil and Gas Industry, C. Surface Use Agreement, (accessed 17

June 2017) at http://www.oilandgasbmps.org/landowners-guide/#7 996 Ibid. 997 Matt Sura, Transportation plans, Colorado Landowner’s Guide to Oil and Gas Development, Part VI –

Negotiating with the Oil and Gas Industry, C. Surface Use Agreement, (accessed 17 June 2017) at

http://www.oilandgasbmps.org/landowners-guide/#7 998 Ibid. 999 Ibid. 1000 Ibid. 1001 Mattt Sura, Additional equipment and facilities, Colorado Landowner’s Guide to Oil and Gas

Development, Part VI – Negotiating with the Oil and Gas Industry, C. Surface Use Agreement, (accessed 17

June 2017) at <http://www.oilandgasbmps.org/landowners-guide/#7

148

When drafting surface use agreements the Colorado guide encourages landowners to take

into account the possibility of surface disturbance; interim reclamation (what will land

look like when operators are finished extracting gas); pits (will waste storage be allowed

on a property); waste disposal (how will liquid and solid waste be disposed of);

groundwater impacts; noise impacts; dust impacts; visual impacts; water rights; fencing;

damages; timing (the timing of the operations and whether they will disrupt agricultural

uses) and current use (are there current or future uses of the land that must be

accommodated eg. livestock, irrigated farmland, future housing development, etc.).

There are various protections that can be included as requirements for approval in drilling

permits or oil and gas location assessments1002 which are enforced by the COGCC.1003 The

Colorado guide suggests that these inspections give surface owners an opportunity to influence

COGCC staff to insert additional protective conditions into the drilling permit.1004 The COGCC

is not involved in surface owner compensation issues or other private party negotiations

between an operator and the surface owner.1005 A landowner with no right to minerals below

the surface can influence negotiations by relying on the ‘reasonable accommodation’ provision

in the OGCA.1006

4.1.5 Conclusion

The use of non-statutory based access agreements in Western Australia and South Australia is

not appropriate to manage the relationship between operators and landowners. The author has

no faith in the use of these agreements if they are not underpinned by legislation. These

agreements are private agreements and it is highly likely that any power imbalances, whether

real or perceived, would be alleviated by some involvement by the respective state regulators

in the negotiation process. For example, it should not be left to industry groups to develop

guidelines and tools to assist petroleum title holders and farmers to reach fair and equitable

1002 Rule 303(b) of the COGCC at <https://cogcc.state.co.us/documents/reg/Rules/LATEST/300Series.pdf>;

Form 2A at <https://cogcc.state.co.us/documents/reg/Forms/PDF_Forms/Form2A_20130806.pdf> 1003 Colorado Oil and Gas Conservation Commission, Enforcement Guidance and Penalty Policy, January 2015

at <http://cogcc.state.co.us/documents/reg/Policies/EnforcementGuidance.pdf> 1004 Rule 303 of the COGCC at <https://cogcc.state.co.us/documents/reg/Rules/LATEST/300Series.pdf> 1005 Matt Sura, Colorado Landowner’s Guide to Oil and Gas Development, B. “Bonding On” Without a surface

use agreement, (accessed 17 June 2017) at http://www.oilandgasbmps.org/landowners-guide/#7 1006 Section 34-60-127 of the OGC Act at <http://www.lexisnexis.com/hottopics/Colorado/>

149

agreements.1007 Western Australia’s land access regime would benefit if the DMIRS

expectation of stakeholder interaction had a statutory foundation. The author favours

Colorado’s reasonable accommodation provision as a mechanism to assist landowners in their

negotiations with operators.1008 The provision requires operators to only disturb the amount of

land that is "reasonable and necessary" to extract gas.1009

4.2 Water

Water is likely to dominate the shale and tight gas debate for the foreseeable future.1010 Some

industry commentators argue that ‘drought and increasing competition for water have only

heightened the need for effective water management strategies.’1011 The implementation of

effective water management and regulatory regimes to protect water resources and the

encouragement of sustainable practices and efficient use will enable operators to exploit shale

and tight gas with less community opposition. There is little disagreement that the handling

and disposal of waste water is the single greatest environmental impediment to natural gas and

oil exploration and production.1012

1007 WA Farmers, PGA, APPEA, Vegetables WA, Explanation of the Land Access Agreement Template for

Petroleum Activities under the Petroleum and Geothermal Energy Resources Act 1967, October 2015 at

https://www.appea.com.au/wp-content/uploads/2015/10/Final-Land-Access-Template-Explanation-Oct-

2015.pdf 1008 Section 34-60-127 of the OGC Act at <http://www.lexisnexis.com/hottopics/Colorado/> 1009 Section 34-60-127 of the OGC Act at <http://www.lexisnexis.com/hottopics/Colorado/> 1010 Carlos R. Romo & Molly Cage, State policy and technological innovation in hydraulic fracturing water

management, ABA Section of Environment, Energy and Resources, Trends March/April 2014 1011 Ibid 1012 World Energy Outlook, Golden Rules for Golden Age of Gas, World Energy Outlook Special Report on

Unconventional Gas, (2012) at 32 at <

https://www.iea.org/media/training/presentations/etw2014/Day_2_Session_2b_Gas_Unconventional.pdf>

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4.2.1 Australia - EPBC Act

The Environment Protection and Biodiversity Conservation Act 1999 (Commonwealth) (EPBC

Act) sets out that ‘actions that have, or are likely to have, a significant impact on a matter of

national significance require approval from the Commonwealth Minister for Environment’.1013

In Australia water resources are considered a matter of national environmental significance

(MNES), with regard to coal seam gas development and large coal mining development (water

trigger). A water resource is ground water or surface water and comprises organisms and

ecosystems that add to the environmental value and physical state of the water resource.1014

The water trigger ensures that the impacts of planned coal seam gas development and large

coal mining developments on water resources are appropriately assessed.1015 The water trigger

does not apply to shale and tight gas. The amendments to the EPBC Act were based on the

objectives of the National Partnership Agreement on Coal Seam Gas and Large Coal

Mining (NPA).1016 An independent review of the water trigger legislation was tabled in the

Commonwealth Parliament in 2017.1017 When the EPBC Act amendments were considered,

some argued its scope should have been expanded to include shale and tight gas.1018 The

independent review insisted that the exclusion of shale and tight gas was deliberate.1019

Specifically, the review determined that:

‘…the objective of the legislation is clear and narrow. It seeks to deal only with the

impacts on water resources of coal seam gas and large coal mining development.

Therefore, the review cannot conclude that the silence of the legislation on shale and

tight gas is other than intentional.’1020

1013 Department of Environment and Energy, What is protected under the EPBC Act, (accessed 19 June 2017)

at < http://www.environment.gov.au/epbc/what-is-protected> 1014 Water resources – 2013 EPBC Act amendment – Water trigger, (accessed 17 June 2017) at

http://environment.gov.au/epbc/what-is-protected/water-resources 1015 Ibid. 1016 Department of Environment and Energy, National Partnership Agreement on Coal Seam Gas and Large

Coal Mining Development, (accessed 17 June 2017) at http://www.environment.gov.au/water/coal-and-coal-

seam-gas/office-of-water-science/npa 1017 Stephen Hunter, Independent Review of the Water Trigger Legislation, April 2017 at <

http://www.environment.gov.au/system/files/resources/905b3199-4586-4f65-9c03-8182492f0641/files/water-

trigger-review-final.pdf> 1018 Stephen Hunter, Independent Review of the Water Trigger Legislation, April 2017, p 33 1019 Stephen Hunter, Independent Review of the Water Trigger Legislation, April 2017, p 50 1020 Stephen Hunter, Independent Review of the Water Trigger Legislation, April 2017, p 50

151

Western Australia’s Standing Committee on Environment and Public Affair identified ‘that the

emergence of an unconventional gas industry in WA was a source of community interest and

concern’.1021 Several years later, the Commonwealth government advised a select committee

on unconventional gas that the remoteness and scale of Australia’s shale gas and tight gas

operations has, to date, reduced community impact and concern.1022

The handling and disposal of water is the single greatest environmental obstacle to shale and

tight gas exploitation and it is concerning that the water trigger has not been extended. It is

likely that the exploitation of shale and tight gas will threaten water resources in some way.

The negative impacts on water resources, if not properly managed, have the capacity to cause

significant environmental and production issues beyond immediate production areas. There is

also a risk to drinking water supplies through contamination. The EPBC Act should include

shale and tight gas as a water trigger.

4.2.2 The United States

The Pollution Control Act of 1948 (United States) was the first major United States law to

address water pollution. It authorised the Surgeon General of the Public Health Service to

prepare comprehensive programs for eradicating or decreasing the pollution of interstate waters

and tributaries and improving the sanitary condition of surface and underground waters.1023

Increased public awareness and concerns for controlling water pollution in the United States at

the time led to comprehensive amendments in 1972.

The result of these amendments was the Federal Water Pollution Control Act of 1948 (United

States) or as it widely known, the Clean Water Act (CWA). The CWA established the structure

1021 Standing Committee on Environment and Public Affairs, Parliament of Western Australia, Implications for

Western Australia of Hydraulic Fracturing for Unconventional Gas, November 2015 1022 Australian Government Submission to the Select Committee on Unconventional Gas Mining,

Unconventional Gas Mining Submission 123, March 2016

http://www.parliament.wa.gov.au/Parliament/commit.nsf/RelatedReportsLookup/74E61E739E39E57748257E

F9002150FE?OpenDocument

https://www.aph.gov.au/Parliamentary_Business/Committees/Senate/Gasmining/Gasmining/Submissions 1023 United States Environmental Protection Agency, Laws and Regulations, History of the Clean Water Act (15

January 2018)

152

for regulating pollutant discharges; gave the US Environmental Protection Agency (EPA) the

authority to implement pollution control programs; maintain existing requirements to set water

quality standards for all contaminants in surface water; made it unlawful to discharge

pollutants; funded the construction of sewerage treatment plants and recognised the need for

planning to address the critical problems posed by nonpoint source pollution.1024 The CWA

outlines the National Pollutant Discharge Elimination System (NPDES) permit process which

establishes limits on produced water discharge.

The Comprehensive Environmental Response, Compensation, and Liability Act of 1980

(United States) (CERCLA) provided a ‘superfund’ to ‘clean up uncontrolled or abandoned

hazardous waste sites as well as accidents, spills, and other emergency releases or pollutants

and contaminants into the environment’.1025 Shale gas production in the United States is not

subject to CERCLA.1026 The Safe Drinking Water Act of 1974 (United States) (SDWA) was

implemented to protect the quality of drinking water in the United States.1027 The SDWA

sanctioned the EPA to establish minimum standards to protect tap water and required all

owners or operators of public water systems to comply.1028 The Underground Injection Control

program was launched by the SDWA to protect underground drinking water from

contamination.

The Energy Policy Act of 2005 (United States) exempted hydraulic fracturing from the SDWA

and CWA. A provision in the Act sets out that the definition of ‘underground injection’ did

not include the injection of fluids or specified propping agents. This provided an exemption

for drilling and extraction activities and the requirement of groundwater contamination under

the SDWA. The Fracturing Responsibility and Awareness of Chemicals Act of 2017 (United

States) (the Frac Act) was introduced into Congress in 2017 to amend the SDWA to repeal the

hydraulic fracturing exemption.1029

1024 Ibid. 1025 United States Environmental Protection Agency, Laws and Regulations, Summary of the Comprehensive

Environmental Response, Compensation and Liability Act (Superfund) (15 January 2018) 1026 Simon Robb, ‘A best practice regulatory proposal for shale gas production’, Doctor of Juridical Science

thesis, The University of Western Australia, 2014, pg 116 1027 United States Environmental Protection Agency, Laws and Regulations, Summary of the Safe Drinking

Water Act (15 January 2018) 1028 Ibid. 1029 The Frac Act (2017) (United States) at https://www.congress.gov/bill/115th-congress/senate-bill/865/text

153

4.2.3 Western Australia

The use of water in hydraulic fracturing is regulated by three statutes: the PGERA that regulates

petroleum exploration and production activities; the RiWI Act that regulates the taking and use

of water; and the environmental protection legislation that regulates discharges of waste. The

PGERA is administered by the DMIRS and the water resources and environmental protection

legislation by the DoWER.

The PGERA gives operators land tenure access to water resources under the authorisation of a

permit, drilling reservation, access authority, special prospecting authority, lease or licence.1030

The taking and use of water for the purposes of gas operations is subject to the RiWI Act.1031

The right to the use, flow and control of water in Western Australia is vested in the Crown and,

in most cases, activities for the taking of water resources needs specific licence authority.1032

The construction of all artesian wells or bores, and all non-artesian wells within proclaimed

groundwater management areas, also needs to be licensed.1033 Western Australian operators

require licences if they want to take water for drilling wells and for hydraulic fracturing.1034

There is no licencing instrument under the RiWI Act to regulate the injection of water or fluids

into the ground for hydraulic fracturing activities. These activities are regulated under PGERA.

The reuse or disposal of wastewater is regulated in accordance with the PGERA Environment

Regulations as part of the approvals process.

The DoWER and DMIRS have an administrative agreement in place to support co-operation

in relation to the consideration of potential impacts on water resources by petroleum and

geothermal activities regulated under the PGERA.1035 If the DMIRS receives an EP proposing

petroleum activities in ‘a public drinking water source area or within five kilometres of public

drinking water source area water bore or aboriginal community drinking water bore’, the

DMIRS provides the DoWER with a copy of the EP and asks that they provide advice on the

1030 Petroleum and Geothermal Energy Resources Act 1967 (WA), s 7 1031 Petroleum and Geothermal Energy Resources Act 1967 (WA), s 7(3) 1032 Rights in Water and Irrigation Act 1914 (WA), ss 5A and 5C. 1033 Rights in Water and Irrigation Act 1914 (WA), ss 26A and 26D 1034 Rights in Water and Irrigation Act 1914 (WA), s 5C 1035 Administrative Agreement between the DMIRS and DoW For Onshore Petroleum and Geothermal

Activities in Western Australia, July 2015 at

http://www.water.wa.gov.au/__data/assets/pdf_file/0007/7468/109380.pdf

154

proposal and not approve it until advice is obtained.1036 If the DMIRS receives an EP proposing

petroleum activities outside a public drinking water source area they will provide a copy to the

DoWER.1037 The DoWER will advise the DMIRS whether they want to review the EP and

request that it not be approved until they have provided comment.1038

There is a capacity under Part V of the Environmental Protection Act 1986 (WA) (EP Act) to

manage the impacts of specific development projects on water resources.1039 Under Part V

Division 3, specified industrial premises that could cause emissions and discharges to air, land

or water are known as ‘prescribed premises’ and trigger regulation by the DoWER.1040 Natural

gas processing facilities become prescribed if they process more than 5,000 tonnes of gas per

year.1041 The DoWER regulates the construction and operation of above ground facilities after

gas has been extracted from below the ground.1042 It does not regulate the extraction of gas

that occurs below the ground which includes the construction and installation of gas wells, and

the operation of hydraulic fracture stimulation processes.1043

Western Australia’s guideline for groundwater monitoring for shale and tight gas operations

applies to monitoring of groundwater resources for regulated activities under the PGERA and

associated regulations.1044 The guideline covers groundwater monitoring programs for new

shale and tight gas operations with regard to drilling, well construction, well work-over,

injection, well production testing, hydraulic fracture stimulation, construction and installation

1036 Id at 4. 1037 Ibid. 1038 Ibid. 1039 Environmental Protection Act 1986 (WA), Part V 1040 Department of Environment Regulation, Government of Western Australia, Regulation of natural gas

from shale and tight rocks, Industry Regulation Fact Sheet 1, (accessed 18 June 2017) at

https://www.der.wa.gov.au/images/documents/our-work/licences-and-works-approvals/fact-

sheet/regulation_of_natural_gas_fs.pdf 1041 Environmental Protection Regulations 1987(WA), Category 10, Schedule 1 1042 Department of Environment Regulation, Government of Western Australia, Regulation of natural gas

from shale and tight rocks, Industry Regulation Fact Sheet 1, (accessed 19 June 2017) at

https://www.der.wa.gov.au/images/documents/our-work/licences-and-works-approvals/fact-

sheet/regulation_of_natural_gas_fs.pdf 1043 Ibid. 1044 Department Mines and Petroleum and Department of Water, Guideline for Groundwater Monitoring in the

Onshore Petroleum and Geothermal Industry, , July 2016, pg 4,

http://www.water.wa.gov.au/__data/assets/pdf_file/0019/8812/164265_Groundwater-

Monitoring_Guideline.pdf

155

of a facility, operation and modification of a facility, storage and processing of petroleum and

decommissioning of a well or facility.1045

The requirements to monitor groundwater are established on a case-by-case basis subject to the

scale and type of operation, level of risk and sensitivity and values of the environment

(including aquifers).1046 If there is an increased risk that groundwater resources or sensitive

environments will be negatively impacted, more intensive baseline and surveillance

groundwater monitoring programs may be required – including multiple monitoring bores at

different locations and depths in the aquifer, along with greater sampling frequency and with

additional chemical parameters.1047

According to the guideline, rigorous monitoring programs are suitable where activities are

occurring in areas that are close to potable water supplies such as public drinking water source

areas (PDWSA), a PDWSA water bore, Aboriginal community drinking water bore, close to

environmentally sensitive areas, in geological areas where there is the potential to rapidly

mobilise groundwater contaminants such as faults and karst geology, areas with important

groundwater values and beneficial uses, close to populated areas, culturally significant areas

and where there is significant public concern or perceived risks, where there is a known risk of

groundwater contamination, areas with higher operational risks, or where the proposed activity

has a high level of complexity, uncertainty or risk.1048

Those activities that pose a low risk to groundwater or are occurring in areas where there are

no sensitive or water-dependent environments or water users in the vicinity of the proposed

activity require less intensive monitoring programs.1049 The guideline states that there may

be activities where groundwater monitoring is not considered appropriate, for example

seismic, geological and aerial surveys, construction and operation of pipelines, small scale

geothermal wells.1050

1045 Ibid. 1046 Id at 5. 1047 Ibid. 1048 Ibid. 1049 Id at 6. 1050 Ibid.

156

The guideline sets out that existing groundwater monitoring programs should be reviewed

where an activity is moving from exploration to production.1051 The EPA may require

additional baseline groundwater information if an environmental impact assessment is

required under the EPA. Operators must liaise with public water service providers if their

activities are carried out in a PDWSA, within 5 km of a PDWSA, or within 5km of a public

water bore.1052 If the activity is within 5km of a bore supplying an Aboriginal community,

the relevant public water service provider is the Housing Authority1053

4.2.4 South Australia

The PGEA states that the Minister must, in acting in the administration of the Act, take into

account the objects of the NRM Act.1054 An operator that holds an exploration1055 or production

licence1056 must provide for their water requirements within the framework of the NRM Act,

like all other water users. The PGEA sets out that the Minister must have regard to, and seek

to further, the objects of the NRM Act.1057 Under the NRM Act, any water use must be carried

out in accordance with the principles set out in the appropriate Regional NRM Plan1058 and

Water Allocation Plan (WAP).1059 A WAP sets out the rules for managing, taking and using

prescribed water. They offer security and equity to water users while balancing the capacity

of a region’s overall resources and the needs of the environment.1060

Water licences are granted for prescribed resources1061 including source water for hydraulic

fracturing operations.1062 The issuing of permits to drill water wells is also regulated under this

1051 Ibid. 1052 Id at 8. 1053 Ibid. 1054 Petroleum and Geothermal Energy Act 2000 (SA), s 6A 1055 Petroleum and Geothermal Energy Act 2000 (SA), s 21(1) 1056 Petroleum and Geothermal Energy Act 2000 (SA), s 34 1057 Petroleum and Geothermal Energy Act 2000 (SA), s 95 1058 Natural Resource Management Act 2004 (SA), s 75 1059 Natural Resource Management Act 2004 (SA), s 76 1060 Ibid. 1061 Natural Resources Management Act 2004 (SA), s 146(1) 1062 Department of Environment and Water, Unconventional Gas mining planning in the South East What are

the roles of Government bodies in this issue?, (accessed 15 June 2017) at

http://www.environment.sa.gov.au/Home/Search_Results?dlv_Site%20Wide%20Search%20Results=(keyword

=shale%20gas)

157

legislation.1063 Well approval is given under the petroleum and geothermal energy

legislation.1064 The NRMA administers authorisations,1065 issues access entitlements,1066

allocations1067 (licensing),1068 water transfers,1069 works, site use approvals and compliance

activities.1070 The granting of a water licence covers prescribed watercourses, lakes, wells or

surface water.1071 A water licence provides an operator with an entitlement (water access

entitlement) to gain access to a share of water available in consumptive pools.1072 An operator

who has lawful access to water may take it for any purpose.1073 The occupier of land is entitled

to take surface water for any purpose.1074

The grant of a water licence under the NRMA includes source water for hydraulic fracturing

operations. The issuing of permits to drill water wells is also regulated under the NRMA. Well

approval is given under the PGEA. The NRMA administers authorisations, issues access

entitlements, allocations (licensing), water transfers, works, site use approvals and compliance

activities. Permits to construct repair or backfill wells are administered by the DEWNR on

behalf of the Minister. The granting of a water licence covers prescribed watercourses, lakes,

wells or surface water. A water licence provides an operator with an entitlement (water access

entitlement) to gain access to a share of water available in consumptive pools. An operator

who has lawful access to water may take it for any purpose. The occupier of land is entitled to

take surface water for any purpose.

The Cooper Basin Petroleum Productions Operations, Statement of Environmental Objectives

sets out that wastewater disposal is undertaken in accordance with the Public Health

(Wastewater) Regulations 2013 (SA) which requires that the disposal system is managed in

1063 Natural Resources Management Act 2004 (SA), s 139 1064 Petroleum and Geothermal Energy Act 2000 (SA), s 10(d) 1065 Natural Resources Management Act 2004 (SA), s 226 1066 Natural Resources Management Act 2004 (SA), s 146(2) 1067 Natural Resources Management Act 2004 (SA), s 152 1068 Natural Resources Management Act 2004 (SA), s 146 1069 Natural Resources Management Act 2004 (SA), s 150 1070 Department of Environment and Water, Unconventional Gas mining planning in the South East What are

the roles of Government bodies in this issue?, (accessed 18 June 2017) at

http://www.environment.sa.gov.au/Home/Search_Results?dlv_Site%20Wide%20Search%20Results=(keyword

=shale%20gas) 1071 Natural Resources Management Act 2004 (SA), s 146(1) 1072 Ibid s 146(2) 1073 Natural Resources Management Act 2004 (SA), s 124(1) 1074 Natural Resources Management Act 2004 (SA), s 124(2)

158

accordance with the Environment Protection (Water Quality) Policy 2015.1075 Any impacts

that result from produced formation water treatment and disposal, and restricting it to defined

areas, is reduced by adhering to the requirements of the Environment Protection Act 1993 (SA),

Environment Protection (Water Quality) Policy 2015, relevant conditions of any EPA

Authorisations and the NRMA. To reduce land contamination and avoid water contamination,

the location, design and operation of facilities is consistent with the requirements of the

Environment Protection (Water Quality) Policy 2015.

4.2.5 Colorado

Access to water in Colorado is based on the ‘prior appropriation system’.1076 The doctrine is

embedded in jurisprudence, through constitutional and statutory provisions, and by a line of

judicial decisions.1077 The right to appropriate water for a beneficial use is well established.1078

An appropriation is best described as the intent to take water accompanied by a physical

demonstration of intent.1079 The system controls who uses water, how much water they use,

the types of uses allowed, and when that water can be used.1080 The first person to appropriate

and use water has the first right to use the water within a particular stream system. The person

then becomes the senior water right holder on the stream, and that water right must be satisfied

before any other water rights can be fulfilled.1081 The Constitution provides that water of any

natural stream not already appropriated is declared to be the property of the public, and

dedicated to the use of the people of the State, subject to appropriation.1082 When this

abovementioned water is not adequate for the service of those desiring to use it, those using

the water for domestic purposes have preference over those claiming for any other purpose,

1075 Beach Energy, Statement of Environmental Objectives, Cooper Basin Petroleum Production Operations,

(accessed 12 May 2017) pg 15,

http://www.beachenergy.com.au/irm/company/showpage.aspx?CategoryId=190&CPID=6631&InstanceVersio

nNumber=0 1076 Colorado Division of Water Resources, Department of Natural Resources, Prior Appropriation Law at

http://water.state.co.us/surfacewater/swrights/pages/priorapprop.aspx 1077 Comstock v. Larimer Weld Reservoir Co., 58 Colo. 186, 145 P. 700, 1916A Ann. Cas. 416(1914) 1078 Metro. Sub. Water Users Ass'n v. Colo. River Water Conservation Dist., 148 Colo. 173, 365 P.2d 273

(1961) 1079 Elk-Rifle Water Co. v. Templeton, 173 Colo. 438, 484 P.2d 1211 (1971) 1080 Colorado Division of Water Resources, Department of Natural Resources, Prior Appropriation Law at

http://water.state.co.us/surfacewater/swrights/pages/priorapprop.aspx 1081 Ibid. 1082 Constitution of Colorado (1876) ss 5 and 6 of Article XVI

159

and those using the water for agricultural purposes have preference over those using it for

manufacturing.1083

The GWMA affirms, with respect to the designated ground waters, the long-established policy

requiring that water resources be dedicated to beneficial use in reasonable amounts through

appropriation.1084 All designated ground waters in Colorado are declared to be subject to

appropriation.1085 The State’s water legislation deals with applications for groundwater, public

notices, conditional permits, hearing on objections and well permits.1086 An operator who

wishes to appropriate groundwater for a beneficial use in a designated groundwater basin must

apply to the Ground Water Commission (GWC), specifying the exact basin or subdivision from

which water is intended to be appropriated.1087 The application must include, amongst other

things, an outline of the beneficial use to which it is intended to use the water, the location of

the planned well, the projected average annual amount of water applied for in acre-feet, the

projected maximum pumping rate in gallons per minute.1088 The water that is subject to the

application can only be used on the land named in the application.1089

An application for an initial appropriation of ground water, even if not within the definition of

designated ground water, in a designated ground water basin must be directed to the GWC.1090

An application that is granted positive consideration by the GWC is published within thirty

days.1091 If an objection is filed the GWC, a date will be set for a hearing. After the hearing if

it appears that there are no ‘unappropriated waters in the designated source or that the proposed

appropriation would unreasonably impair existing water rights from such source or would

create unreasonable waste, the application shall be denied; otherwise, it shall be granted.’1092

1083 Colorado Division of Water Resources, Synopsis of Colorado Water Law, (accessed 1 May 2017) at <

https://openei.org/wiki/Colorado_Division_of_Water_Resources,_Synopsis_of_Colorado_Water_Law> 1084 Ground Water Management Act (Colorado), § 37-90-102 1085 Ground Water Management Act (Colorado), § 37-90-102(1) 1086 Ground Water Management Act (Colorado), § 37-90-107 1087 Ground Water Management Act (Colorado), § 37-90-107(1) 1088 Ground Water Management Act (Colorado), § 37-90-107(1) 1089 Ground Water Management Act (Colorado), § 37-90-107(1) 1090 State ex rel. Danielson v. Vickroy, 627 P.2d 752 (Colo. 1981) 1091 Ground Water Management Act (Colorado), § 37-90-107(2) 1092 Ground Water Management Act (Colorado), § 37-90-107(4)

160

The GWC must consider appropriative intent in considering an application for appropriating

designated ground water1093 and is authorised to reject an application if it finds that the intended

appropriation will unduly harm existing water rights from the same source, or will create

unreasonable waste.1094

Subsequent to conditional permits to appropriate designated groundwater, an applicant, within

one year from the date of the issuance of the permit, must construct the well or other works

necessary to apply the water to a beneficial use.1095 Once the well is constructed, the applicant

must advise the GWC as to the depth of the well, the water-bearing formations intercepted by

the well and the maximum sustained pumping rate in gallons per minute.1096A final permit is

essential to the legislative scheme for the administration of ground water rights.1097

Colorado’s surface water is protected by the utilisation of internal, intermediate, and external

buffer areas.1098 The rules safeguard surface public water sources by compelling additional

protections when gas facilities are planned within a half-mile (804.672 metres) of a designated

surface water source and by preventing gas facilities being located within 350 feet (106.68

metres) from designated water sources.1099 In Colorado, wells and production facilities must

not be located within 500 feet of buildings and 1000 feet (304.8 metres) from those with high

occupancy.1100

Operators must carry out preliminary baseline sampling and subsequent monitoring of all

available water sources (up to a maximum of four) within a one-half mile (1.6 km) radius of a

1093 Jaeger v. Colo. Ground Water Comm'n, 746 P.2d 515 (Colo. 1987) 1094 Fundingsland v. Colo. Ground Water Comm'n, 171 Colo. 487, 468 P.2d 835 (1970) 1095 Ground Water Management Act (Colorado), s 37-90-108(1)(a) 1096 Ground Water Management Act (Colorado), s 37-90-108(1)(b) 1097 Thompson v. Colo. Ground Water Comm'n, 194 Colo. 489, 575 P.2d 372 (1978) 1098 COGCC rule 317B.b at <

https://cogcc.state.co.us/documents/reg/Rules/LATEST/Complete%20Rules%20as%20of%20May%201,%202

018.pdf> 1099 COGCC rule 317B at <

https://cogcc.state.co.us/documents/reg/Rules/LATEST/Complete%20Rules%20as%20of%20May%201,%202

018.pdf> 1100 COGCC rule 604(2) at <

https://cogcc.state.co.us/documents/reg/Rules/LATEST/Complete%20Rules%20as%20of%20May%201,%202

018.pdf>

161

proposed gas well, multi-well site, or dedicated injection well.1101 Subsequent sampling must

be conducted at the initial sample locations between six and twelve months, and a second

subsequent sampling event shall be conducted between 60 and 72 months following completion

of the well or dedicated injection well, or the last well on a multi-well site.1102

Colorado’s protection of water extends to floodplains, and through obligations to report spills

and releases.1103 This protection is diminished when it comes to existing gas well sites

earmarked for expansion (the COGCC grandfathers existing well pads that were in place before

2008).1104 The standards for groundwater and site-specific water quality classifications are

accepted by Colorado’s Water Quality Control Commission.1105 The COGCC adopted a rule

requiring baseline and post-completion groundwater monitoring in 2012.1106 Colorado has

comprehensive rules in relation to cement bond logs1107, mechanical integrity tests1108, and

bradenhead tests,1109 which are all important elements for securing the integrity of wells.1110

Baseline water sampling is not uniform across the State of Colorado. For example, the Greater

1101 COGCC rule 609(b) at <

https://cogcc.state.co.us/documents/reg/Rules/LATEST/Complete%20Rules%20as%20of%20May%201,%202

018.pdf> 1102 COGCC rule 609(d)(3)B at <

https://cogcc.state.co.us/documents/reg/Rules/LATEST/Complete%20Rules%20as%20of%20May%201,%202

018.pdf> 1103 COGCC rule 906 at <

https://cogcc.state.co.us/documents/reg/Rules/LATEST/Complete%20Rules%20as%20of%20May%201,%202

018.pdf> 1104 University of Colorado at Boulder, Protecting Source Water in Colorado During Oil and Gas

Development, August 2016, iii at

<http://www.oilandgasbmps.org/docs/CO186_ProtectingSourceWaterAugust2016.pdf> 1105 Water Quality Control Commission at https://www.colorado.gov/pacific/cdphe/wqcc 1106 COGCC rule 609 at <

https://cogcc.state.co.us/documents/reg/Rules/LATEST/Complete%20Rules%20as%20of%20May%201,%202

018.pdf> 1107 COGCC rule 317.p at <

https://cogcc.state.co.us/documents/reg/Rules/LATEST/Complete%20Rules%20as%20of%20May%201,%202

018.pdf> 1108 COGCC rule 316B at <

https://cogcc.state.co.us/documents/reg/Rules/LATEST/Complete%20Rules%20as%20of%20May%201,%202

018.pdf> 1109 COGCC rule 314 at <

https://cogcc.state.co.us/documents/reg/Rules/LATEST/Complete%20Rules%20as%20of%20May%201,%202

018.pdf> 1110 COGCC rule 308A.b at <

https://cogcc.state.co.us/documents/reg/Rules/LATEST/Complete%20Rules%20as%20of%20May%201,%202

018.pdf>

162

Wattenberg Area, the location where most gas production occurs in Colorado has a more

restricted groundwater monitoring regime.1111

Colorado has wide-ranging groundwater quality protection rules administered by the COGCC,

such as obligations to carry out baseline water testing1112 and rules governing drilling1113 (for

example, well casing and cementing). The COGCC rules include restrictive groundwater

monitoring regulations1114 and the requirement for baseline and post line testing of gas

wells.1115 Colorado has restrictive stormwater rules applicable to shale and tight gas activities

and a complex system of water rights laws.1116 The Intermountain Oil and Gas BMP Project’s

best management practices and database for shale and tight gas development contain

mandatory and voluntary best management practices.1117 The Water Quality Control Act

(Colorado) has a role in regulating the environmental impacts of shale and tight gas

development.

In Colorado, operators must not discharge pollutants into State water without a permit from the

water quality control division.1118 The Water Quality Control Act (Colorado) includes

provisions for oversight and enforcement of permits for point source discharges and for

reporting of non-permitted discharges.1119 Neither the act nor the regulations requires specific

compliance or enforcement responses for point source discharges that occur without a permit

1111 COGCC rule 318A.f at <

https://cogcc.state.co.us/documents/reg/Rules/LATEST/Complete%20Rules%20as%20of%20May%201,%202

018.pdf> 1112 COGCC rule 908(9)(A) at <

https://cogcc.state.co.us/documents/reg/Rules/LATEST/Complete%20Rules%20as%20of%20May%201,%202

018.pdf> 1113 COGCC rule 317e at <

https://cogcc.state.co.us/documents/reg/Rules/LATEST/Complete%20Rules%20as%20of%20May%201,%202

018.pdf> 1114 Stephanie Neitzel, P.E. Esq. Principal WaterRich Advisors LLC, Centennial, Colorado, Water Quality

Regulations for Unconventional Gas Production, United States and Australia Comparison (accessed 17 June

2017) pg 4 at < http://www.awa.asn.au/documents/136%20SNeitzel.pdf> 1115 Ibid. 1116 Id at 5. 1117 The University of Colorado, Getches-Wilkinson Centre for Natural Resources, Energy, and the

Environment hosts a website of best management practices, (accessed 12 June 2017) at <

http://www.oilandgasbmps.org/> 1118 Water Quality Control Division, Implementation Policy, Reporting of Surface Water Discharge Associated

with Residential and Landscape Irrigation, Colorado Department of Public Health and Environment, [DATE]

https://www.colorado.gov/pacific/sites/default/files/WQCD_Irrigation_Discharge_Policy_151208_signed.pdf 1119 Ibid.

163

or for failure to report a non-permitted discharge.1120 These are covered within policies and

procedures.1121

4.2.6 Conclusion

The author cautiously supports the DoWER and DMIRS administrative agreement which is

intended to boost co-operation in relation to the consideration of potential impacts on water

resources by activities regulated under the PGERA. It is unsatisfactory that although the

DoWER regulates the construction and operation of above ground facilities following gas

extraction from below the ground it does not regulate the extraction of gas that occurs below

the ground which includes the construction and installation of gas wells, and the operation of

hydraulic fracture stimulation processes.

The Western Australian guideline for groundwater monitoring is a useful document and the

author favours the case-by-case monitoring approach which is determined subject to the scale

and type of operation, level of risk and sensitivity and values of the environment.1122 The

author supports the water protection guideline that sets out that operators must liaise with

public water service providers in particular circumstances i.e., where activities are carried out

in a PDWSA, within 5 km of a PDWSA, or within 5 km of a public water bore.1123

The author favours South Australia’s Environment Protection (Water Quality) Policy 2015 that

covers the management of wastewater disposal systems and produced formation water

disposal. The Environment Protection (Water Quality) Policy 2015 also deals with land

contamination and water contamination through location, design and operation of facilities.

The author supports Colorado’s surface water protection mechanism i.e., the use of internal,

intermediate, and external buffer areas. The COGCC rules safeguard surface public water

sources by compelling additional protections when gas facilities are planned within a specified

1120 Ibid. 1121 Ibid. 1122 Department Mines and Petroleum and Department of Water, (WA), Guideline for Groundwater Monitoring

in the Onshore Petroleum and Geothermal Industry, July 2016, pg 5,

http://www.water.wa.gov.au/__data/assets/pdf_file/0019/8812/164265_Groundwater-

Monitoring_Guideline.pdf 1123 Id at 8.

164

distance from a designated surface water source. Wells and production facilities must not be

located within a specified distance building, particularly those with high occupancy.

Preliminary baseline sampling and subsequent monitoring of all available water sources within

a specified distance should be mandatory for any shale and tight gas operations. Subsequent

sampling should be carried out at initial sample locations between six and twelve months, and

subsequent sampling thereafter.

Baseline water sampling is not uniform across the state of Colorado. For example, the Greater

Wattenberg Area, the location where most gas production occurs in Colorado has a more

restricted groundwater monitoring regime. Colorado’s wide-ranging groundwater quality

protection rules administered by the COGCC are supported by the author. These include

obligations to undertake baseline water testing. .

4.3 Drilling and fracturing

The COGCC actively encourages and promotes waste minimisation by allowing operators to

submit management plans to the COGCC that deal with beneficial use, reuse and recycling.

The DMIRS and DPC should do the same. This thesis favours the COGCC underground

injection authorisation regime over that which is fairly non-existent in Western Australia and

South Australia. The process in Colorado appears logically based. An operator must not

dispose of water underground or commence construction of a well for the purpose of

underground injection without having first received written authorisation from the COGCC.

They must submit several application forms along with a service and filing fee. The COGCC

may refuse to issue a permit and approve underground injection if it considers that the disposal

well could result in a significant adverse impact on the environment.

165

4.3.1 Flow-back, produced water, recycling and reuse

Flow-back and produced water are the two main sources of waste that require management

during gas production.1124 In the United States, flow-back water management options are

extensive and include direct reuse without treatment; on-site treatment and reuse; off-site

treatment and reuse; and off-site treatment and disposal. Direct reuse incurs minimal cost, on-

site treatment reconditions the water at a moderate cost, off-site treatment and reuse incurs high

transportation costs while off-site treatment and disposal incurs high transportation and

disposal costs.1125

The DMIRS suggests that fracking fluid can be recovered at rates of 40 per cent to 70 per cent

and reused in further hydraulic fracturing stimulation programs.1126 The DMIRS has indicated

it would advocate for the treatment and re-use of water on multiple well sites should hydraulic

fracturing occur in the future on multiple wells.1127

According to ACOLA, during production and initial flow back, 30 per cent to 70 per cent of

water injected during fracking is recovered.1128 Some have reported that up to 50 per cent of

the fracturing compounds may remain trapped underground.1129 In 2014, Buru expected that

up to 99 per cent of the water that flowed back from a well would be returned to the formation

at the end of production.1130 Buru aimed to achieve 100 per cent recycling by 2015.1131

1124 American Fuel & Petrochemical Manufacturers, Shale Oil & Gas Production – Water Reuse, Treatment

and Disposal, (accessed 28 June 2017) pg 1 at <https://www.afpm.org/shale_development/> 1125 Pam Boschee, Produced and Flowback Water Recycling and Reuse, 2014 at

http://www.halliburton.com/public/multichem/contents/Papers_and_Articles/web/Feb-2014-Oil-Gas-Facilities-

Article.pdf 1126 Department of Mines and Petroleum, Guide to the Regulatory Framework for April 2015 Shale and Tight

Gas in Western Australia A Whole-of-Government Approach, 2015 Edition, pg 12 at

http://www.DMIRS.wa.gov.au/Documents/Petroleum/WEB_Shale_and_Tight_Gas_Framework.pdf 1127 Department of Mines and Petroleum, ‘Inquiry into the Implications for Western Australia of Hydraulic

Fracturing for Unconventional Gas’, Submission to the Legislative Council Standing Committee on

Environment and Public Affairs, Department of Mines and Petroleum, 2013, p 15 1128 Frogtech, Potential Geological Risks Associated with Shale Gas Production in Australia, January 2013,

pg 28 at

http://www.acola.org.au/PDF/SAF06FINAL/Frogtech_Shale_Gas_Geology_and_Risks%20Jan2013.pdf 1129 Earthworks, ‘Frack Fluids: Injected and Left Behind’ (Fact Sheet), [accessed 1 May 2017] at

http://earthworksaction.org/files/publications/FS_LeftBehind_lowres.pdf 1130 Buru Energy, Buru Energy’s proposed gas developments in the Canning Basin, Questions and Answers,

March 2014, pg 20 at <http://www.buruenergy.com/wp-content/uploads/Proposed-Gas-Developments-

QA.pdf> 1131 Ibid.

166

In certain parts of Colorado:

an estimated 20-30% of the fracking fluid used flows back to the surface as

return flows; the majority of the water is permanently lost and removed from

the hydrological cycle.1132

When the chemical composition of the water coming from the well is similar to the rock

formation rather than the fracking fluid, it is classified as produced water and can continue to

flow as long as a well is in operation.1133 Flow-back is a mixture of fracking fluid and formation

water (i.e., water rich in brine from the targeted shale gas-rich rock).1134

Produced water is naturally occurring water found in shale formations that flows to the surface

during the entire life of a gas well.1135 It has high concentrations of total dissolved solids and

leaches out barium, calcium, iron and magnesium and also contains dissolved hydrocarbons

such as methane, ethane and propane along with naturally occurring radioactive materials

(NORM), for example radium isotopes.1136 Managing and disposing of water after hydraulic

fracturing is challenging given the fluid that returns to the surface within the first seven to 14

days frequently requires treatment for beneficial reuse and/or recycling or be disposed of by

injection.1137

Recycling and/or reuse should be contextualised more broadly in terms of overall water use

and how operators might gain access to water in accordance with the general water resources

law.

1132 Matt Sura, Colorado’s Landowner’s Guide to Oil and Gas Development, Waste Storage and Disposal (Pits,

Injection), (accessed 27 June 2017) at <http://www.oilandgasbmps.org/landowners-guide/> 1133 Bill Chameides, Fracking Water: It’s Just So Hard to Clean, Huff Post, 10 October 2013 at <

https://www.huffingtonpost.com/bill-chameides/fracking-water-its-just-s_b_4045936.html> 1134 Ibid. 1135 The Institute for Energy and Environmental Research for Northeastern Pennsylvania, What is flowback,

and how does it differ from produced water?, (accessed 12 June 2017) at

http://energy.wilkes.edu/pages/205.asp 1136 Ibid. 1137 American Petroleum Institute, Water Management Associated with Hydraulic Fracturing, API Guidance

Document, Hydraulic Fracturing 2, First Edition, June 2010, pg 5 at <

https://www.browntechnical.org/products/api-guidance-document-hf2-water-management-associated-with-

hydraulic-fracturing.html>

167

4.3.1.1 Western Australia and South Australia

The Standing Committee on Environment and Public Affairs recommended that operators

should be encouraged to explore the recycling of wastewater during hydraulic fracturing

operations, where practicable.1138 In response to the Committee, the government stated that

agencies will continue to encourage the recycling of wastewater in accordance with existing

policies.1139

The recycling of drilling and hydraulic fluids is yet to occur in Western Australia since fracture

stimulations have only occurred on single, exploration well sites.1140 The recycling of produced

water depends on the quality and quantity of the water, the local options for alternate uses, and

the possibility of reusing the water for future uses.1141 According to the DoWER, there is

limited demand for recycled water due in part to the cost of treatment and distribution which

is the main obstacle that restricts development of recycled water schemes across Western

Australia.1142

It is likely that the same obstacles would apply to the opportunities for reusing produced water

for purposes other than hydraulic fracturing.1143 The recycling of produced water depends on

the quality and quantity of the water, the local options for alternate uses, and the possibility of

reusing the water for future uses.1144

1138 Standing Committee on Environment and Public Affairs, Parliament of Western Australia, Report 42,

Implications for Western Australia of Hydraulic Fracturing for Unconventional Gas, November 2015 at

<http://www.parliament.wa.gov.au/Parliament/commit.nsf/(Report+Lookup+by+Com+ID)/74E61E739E39E5

7748257EF9002150FE/$file/ev.fra.151117.rpf.042.xx.pdf> 1139 Government response to Report 42, Standing Committee on Environment and Public Affairs, Implications

for Western Australia of Hydraulic Fracturing for Unconventional Gas, (2016) at <

http://www.parliament.wa.gov.au/publications/tabledpapers.nsf/displaypaper/3913895c7a06d337d5c9ab70482

57f79000e5c77/$file/tp-3895.pdf> 1140 Department of Mines and Petroleum, Submission to the Legislative Council Standing Committee on

Environment and Public Affairs, Parliament of Western Australia, Inquiry into the Implications for Western

Australia of Hydraulic Fracturing for Unconventional Gas, October 2013, pg 15 at <

http://www.parliament.wa.gov.au/Parliament/commit.nsf/(Evidence+Lookup+by+Com+ID)/C4EBD44EB7D2

9B4848257C40000F2471/$file/ev.fra.131003.sub.105.department+of+mines+and+petroleum.pdf> 1141 Department of Water, Submission to the Legislative Council Standing Committee on Environment and

Public Affairs, Parliament of Western Australia, Inquiry into the implications for Western Australia of

hydraulic fracturing for unconventional gas, (October 2013), pg 11 at <

http://www.parliament.wa.gov.au/Parliament/commit.nsf/(Evidence+Lookup+by+Com+ID)/674CC1E61A44E

62048257C400011A4E3/$file/ev.fra.131009.sub.115.department+of+water.pdf> 1142 Ibid. 1143 Ibid. 1144 Ibid.

168

4.3.1.2 Colorado

To encourage and promote waste minimisation in Colorado, operators can voluntarily submit

management plans to the COGCC that deal with beneficial use, reuse and recycling.1145 These

plans must describe the type(s) of waste; the proposed use of the waste; method of waste

treatment; product quality assurance; and include a copy of any certification or authorisation

that may be required by other laws and regulations.1146

In line with the American Petroleum Institute (API), operators must undertake significant

planning and have knowledge of the chemical additives they are using in fracking operations

and a general idea of the composition of flow back and produced water.1147 Operators have an

obligation to select compatible additives and focus their efforts on using environmentally

benign ingredients that do not inhibit water treatment initiatives.1148 Under API guidance,

operators must select additives wisely so they enhance the quantity of the fluids that return to

the surface providing more options for recycling and/or reuse and/or disposal.1149 There are

well-developed water treatment services available to operators in the United States enabling

the conservation of freshwater and the recycling of produced and hydraulic fracturing flowback

water.

In many states in the United States, recycling is mandated as a standard in legislation and many

have separate commercial and non-commercial operations, whilst some operators treat water

recycling like solid waste recycling. The recycling and/or reuse of waste water is vital to gas

development.1150 It is normal for flow-back water to be treated and reused in additional drilling

1145 COGCC rule 907 a.(3), Management of E&P Waste, Reuse and Recycling at

<https://cogcc.state.co.us/documents/reg/Rules/LATEST/Complete%20Rules%20as%20of%20May%201,%20

2018.pdf> 1146 Ibid. 1147 American Petroleum Institute, Water Management Associated with Hydraulic Fracturing, API Guidance

Document, Hydraulic Fracturing 2, First Edition, June 2010, pg 5 at <

https://www.browntechnical.org/products/api-guidance-document-hf2-water-management-associated-with-

hydraulic-fracturing.html> 1148 Ibid. 1149 Ibid. 1150 Ibid.

169

and hydraulic fracturing operations in the United States especially on sites where there are

multiple wells.1151

In some states, the recycling of flow-back is not prohibited but not typically done due to the

small size of operations and associated transportation costs.1152 In the United Kingdom, the

method for disposal can be on-site treatment with re-use of water and disposal of remaining

liquids and solids to a suitable licensed waste treatment and disposal facility; removal off site

to a suitable licensed waste treatment and disposal facility and disposal to a special sewer with

the permission of the relevant waste water utility company.1153

Some parts of the United States encourage operators to use alternative sources of water and

recycle waste fluids for hydraulic fracturing.1154 They use their own waste fluids, which

include produced water and flow-back for frac supply purposes. There are specific protocols

for off-site waste fluid treatment and reclamation for frac water supply purposes.1155 Produced

water may be transferred offsite for use in hydraulic fracturing at other wells.1156 Some states

occasionally spread produced water on roads for dust and ice control at the request of local

authorities, although flow-back fluids from hydraulic fracturing may not be spread on roads.1157

In the United States, states are urged to encourage operators to develop and have the adequate

capacity and infrastructure to manage hydraulic fracturing fluids/wastes, including

transportation, recycling, treatment and disposal.1158

In terms of whether this is a practical proposition given distances and transport costs over large

distance there are certainly options available. Flow-back water is the water that comes to the

1151 Department of Mines and Petroleum, Submission to the Legislative Council Standing Committee on

Environment and Public Affairs, Parliament of Western Australia, Inquiry into the Implications for Western

Australia of Hydraulic Fracturing for Unconventional Gas, October 2013, pg 15 at

<http://www.parliament.wa.gov.au/Parliament/commit.nsf/(Evidence+Lookup+by+Com+ID)/C4EBD44EB7D

29B4848257C40000F2471/$file/ev.fra.131003.sub.105.department+of+mines+and+petroleum.pdf> 1152 Department of Natural Resources, Ohio Hydraulic Fracturing State Review, January 2011 at <

https://oilandgas.ohiodnr.gov/portals/oilgas/pdf/stronger_review11.pdf> 1153 Department of Energy & Climate Change, (United Kingdom), Fracking UK shale: water, February 2014

1154 Department of Natural Resources, Louisiana Hydraulic Fracturing State Review, March 2011 at <

http://www.dnr.louisiana.gov/assets/OC/haynesville_shale/071311_stronger_review.pdf> 1155 Ibid.

1156 Carlos R. Romo & J. Scott Janoe, Regulatory Regimes for Recycling Produced and Frac Flowback Water,

2012 at <http://ssrn.com/abstract=2124696> 1157 Department of Natural Resources, Ohio Hydraulic Fracturing State Review, January 2011 at <

https://oilandgas.ohiodnr.gov/portals/oilgas/pdf/stronger_review11.pdf> 1158 Department of Natural Resources, 2014 Stronger Guidelines, 2014 at

<http://www.strongerinc.org/stronger-guidelines>

170

surface after hydraulic fracturing.1159 Produced water is water trapped in underground

formations that returns to the surface along with oil and gas.1160 Produced formation water

refers to water extracted from hydrocarbon reservoirs.1161 The experience in the United States

will be used in order to determine whether the recycling of produced water (to the extent and

of the type) as it happens in that jurisdiction is appropriate in Western Australia given the

difference in conditions and also whether it is necessary in Western Australia for the shale gas

industry. Water that returns to the surface during and after hydraulic fracturing and contains

clays, chemical additives, dissolved metal ions and total dissolved solids (TDS).1162 The

majority of flow back returns to the surface in the first seven to 10 days while the remainder

occurs over a three to four week period.1163

The thesis supports the work undertaken by the University of Colorado’s Intermountain Oil

and Gas BMP Project.1164 Best management practices (BMP’s) are designed to avoid or reduce

impacts caused by shale and tight gas operations to air, water, soil, or biological resources, and

to reduce harmful impacts to the environment and wildlife resources.1165 The Rifle, Silt, New

Castle Community Development Plan (RSNC-CDP) was an innovative project and a new

scheme for how a community and producers could work together to successfully manage

natural gas development. The RSNC-CDP employs responsible development and BMP’s.1166

Under the RSNC-DCP producers agree to provide the public with a semi-annual drilling plan

and an update on changes;1167

1159 AGL, Responses to flowback water FAQ’s, (accessed 12 June 2017) at http://yoursayagl.com.au/welcome-

to-agls-online-community/news_feed/responses-to-flowback-water-faqs 1160 Produced Water Treatment and Beneficial Use Information Centre, About Produced Water (Produced

Water 101), (accessed 12 June 2017) at http://aqwatec.mines.edu/produced_water/intro/pw/ 1161 Department of Mines and Petroleum, (WA), Summary of comments and departmental responses from public

consultation for new environment regulations, Petroleum and Geothermal Environment Regulations &

Guidelines for Preparation and Submission of an Environment Plan, (accessed 15 June 2017) at

http://www.dmp.wa.gov.au/Documents/Petroleum/PD-SBD-NST-115D.pdf 1162 The Institute for Energy and Environmental Research for Northeastern Pennsylvania, What is flowback,

and how does it differ from produced water?, (accessed 12 May 2017) at

<http://energy.wilkes.edu/pages/205.asp> 1163 Ibid.

1164 Intermountain Oil and Gas BMP Project at http://www.oilandgasbmps.org/ 1165 COGCC rules 100 Series at https://cogcc.state.co.us/documents/reg/Rules/LATEST/100Series.pdf 1166 The Rifle, Silt, New Castle Community Development Plan A Collaborative Planning Document between the

RSNC Defined Area Residents, Antero Resources Corp. and Galaxy Energy, 2006, pg 12 at

http://www.oilandgasbmps.org/docs/CO68-RSNCCommunityDevelopmentPlan.pdf 1167 The Rifle, Silt, New Castle Community Development Plan A Collaborative Planning Document between the

RSNC Defined Area Residents, Antero Resources Corp. and Galaxy Energy, 2006, pg 12 at

http://www.oilandgasbmps.org/docs/CO68-RSNCCommunityDevelopmentPlan.pdf

171

Producers agree to transport water in pipelines to centralised facilities rather than by truck.1168

They agree that wastewater should be transported to disposal injection wells1169 and not stored

other than in temporary storage tanks.1170 Producers agree that no evaporative pits are to be

used in the leased areas.1171 That there are set-backs from inhabited dwellings of 500 feet

whenever possible.1172 Producers agree that water quality testing of all domestic wells within

1/2 mile of well pad is undertaken before drilling begins.1173 They agree that water quantity

testing is available when requested by the landowner.1174 Producers agree that all HF

operations shall be conducted with ‘green frac’ methods, utilizing only sand and water as

fracing materials or other "green frac" materials.1175

4.3.2 Beneficial use

The United States insists that water that returns to the surface should be treated as a resource

rather than a waste product.1176 It can be used for subsequent hydraulic fracturing operations

1168 The Rifle, Silt, New Castle Community Development Plan A Collaborative Planning Document between the

RSNC Defined Area Residents, Antero Resources Corp. and Galaxy Energy, 2006, pg 12 at

http://www.oilandgasbmps.org/docs/CO68-RSNCCommunityDevelopmentPlan.pdf 1169 The Rifle, Silt, New Castle Community Development Plan A Collaborative Planning Document between the

RSNC Defined Area Residents, Antero Resources Corp. and Galaxy Energy, 2006, pg 12 at

http://www.oilandgasbmps.org/docs/CO68-RSNCCommunityDevelopmentPlan.pdf 1170 The Rifle, Silt, New Castle Community Development Plan A Collaborative Planning Document between the

RSNC Defined Area Residents, Antero Resources Corp. and Galaxy Energy, 2006, pg 12 at

http://www.oilandgasbmps.org/docs/CO68-RSNCCommunityDevelopmentPlan.pdf 1171 The Rifle, Silt, New Castle Community Development Plan A Collaborative Planning Document between the

RSNC Defined Area Residents, Antero Resources Corp. and Galaxy Energy, 2006, pg 12 at

http://www.oilandgasbmps.org/docs/CO68-RSNCCommunityDevelopmentPlan.pdf 1172 The Rifle, Silt, New Castle Community Development Plan A Collaborative Planning Document between the

RSNC Defined Area Residents, Antero Resources Corp. and Galaxy Energy, 2006, pg 12 at

http://www.oilandgasbmps.org/docs/CO68-RSNCCommunityDevelopmentPlan.pdf 1173 The Rifle, Silt, New Castle Community Development Plan A Collaborative Planning Document between the

RSNC Defined Area Residents, Antero Resources Corp. and Galaxy Energy, 2006, pg 12 at

http://www.oilandgasbmps.org/docs/CO68-RSNCCommunityDevelopmentPlan.pdf 1174 The Rifle, Silt, New Castle Community Development Plan A Collaborative Planning Document between the

RSNC Defined Area Residents, Antero Resources Corp. and Galaxy Energy, 2006, pg 12 at

http://www.oilandgasbmps.org/docs/CO68-RSNCCommunityDevelopmentPlan.pdf 1175 The Rifle, Silt, New Castle Community Development Plan A Collaborative Planning Document between the

RSNC Defined Area Residents, Antero Resources Corp. and Galaxy Energy, 2006, pg 12 at

http://www.oilandgasbmps.org/docs/CO68-RSNCCommunityDevelopmentPlan.pdf 1176 United States Department of the Interior, Bureau of Reclamation, Oil and Gas Produced Water

Management and Beneficial Use in the Western United States, Reclamation, Managing Water in the West,

Science and Technology Program Report No. 157, 2011, pg 2 at

<https://www.usbr.gov/research/AWT/reportpdfs/report157.pdf>

172

but also for agricultural purposes, in the community and to benefit the environment.1177 As a

result of the large volumes of produced water generated in the Western United States and the

developing need for new water supplies, produced water has the potential to augment

conventional water supplies. 1178 Beneficial uses of produced water include livestock watering,

crop irrigation, stream flow augmentation (which has the potential to improve stream habitat

and increase potable water supply)1179 and industrial uses.1180 Produced water can also be

deposited in aquifer storage for future use.1181

There are significant limitations to the use of produced water for beneficial uses outside of the

gas industry, for example there are issues with timing, reliability, limited amounts, and varying

water quality and the costs required to treat the water to levels required by the other uses.1182

The type of beneficial use most suitable for a produced water application is subject to the

geographical location of its generation, the location of the beneficial use, and the constituent

concentrations in the produced water.1183

4.3.3 Well integrity – Western Australia and South Australia

According to Dr Tina Hunter the existing regulatory framework for shale and tight gas

activities in Western Australia are best practice though the regulatory standards required for

environmental plans judged against those for well integrity displays the major failing of

existing regulatory regimes in minimising the environmental impacts of petroleum

1177 Dr. David R. Stewart, Treatment for Beneficial Use of Produced Water and Hydraulic Fracturing

Flowback Water, US EPA Workshop of Wastewater Treatment and Related Modelling for Hydraulic

Fracturing, 2013, pg 1 at <https://www.epa.gov/sites/production/files/documents/stewart_0.pdf> 1178 UNITED STATES Department of the Interior, Bureau of Reclamation, 2011, at

http://www.usbr.gov/research/AWT/reportpdfs/report157.pdf 1179 Plumlee MH, Gurr CJ & Reinhard M, ‘Recycled water for stream flow augmentation: benefits, challenges

and the presence of wastewater-derived organic compounds’ (2012) Nov 1: 438 Sci Total Environ 541-8 at

<http://www.ncbi.nlm.nih.gov/pubmed/23041295> 1180 U.S Department of Interior, Bureau of Reclamation, Oil and Gas Produced Water Management and

Beneficial Use in the Western United States, Reclamation Managing Water in the West, Science and

Technology Program Report No. 157, pg 1 at < https://www.usbr.gov/research/dwpr/reportpdfs/report157.pdf> 1181 Ibid. 1182 CDR Associates, for the Colorado Energy Office & Colorado Mesa University Water Center, Produced

Water Beneficial Use Dialogue, Opportunities and Challenges for Re-Use of Produced Water on Colorado’s

Wester Slope, (2014) pg 11 at < http://www.oilandgasbmps.org/viewpub.php?id=634> 1183 U.S Department of Interior, Bureau of Reclamation, Oil and Gas Produced Water Management and

Beneficial Use in the Western United States, Reclamation Managing Water in the West, Science and

Technology Program Report No. 157, pg 1 at < https://www.usbr.gov/research/dwpr/reportpdfs/report157.pdf> 1183 Ibid.

173

activities.1184 These shortcomings are not confined to the WA’s regulatory framework, but

prevalent in most Australian (and international) jurisdictions.1185 According to Dr Hunter the

regulatory framework fails to minimise the impact of petroleum activities, including shale and

tight gas activities on the environment.1186

In Western Australia, an operator must have an approved WMP for hydraulic fracturing.1187 A

WMP must be appropriate for the well activity; identify risks and set out management

regimes.1188 If an activity relates to the exploration or recovery, the WMP must show that the

risks identified will be managed in a manner that is consistent with good oil field practice and

will not result in the occurrence of significant risk to which the plan relates.1189

WMPs must include specific information, for example they must provide an explanation of the

design, construction, operational activity and management of wells.1190 They must detail the

chemicals used for the purposes of horizontal drilling or hydraulic fracturing and the estimated

total volume and composition of returned fluids and arrangements for the management of those

fluids. 1191 A WMP must be appropriate; identify risks and set out management regimes1192

and show that identified risks will be managed consistent with good oil-field practice.1193 A

WMP must also list the Australian and international standards that apply in relation to each

well activity.1194

A WMP must explain the philosophy of, and criteria for, the design, construction, operational

activity and management of the well; and the possible production or injection activities of the

well, showing that each well activity will be carried out in accordance with sound engineering

1184 Hunter, T. (2014). Minimising the impact of shale and tight gas projects in Western Australia: an assessment

of the existing regulatory framework. APPEA Journal, 83-90 1185 Ibid 1186 Ibid 1187 Petroleum and Geothermal Energy Resources (Resource Management and Administration) Regulations

2015 (WA), r 10 1188 Petroleum and Geothermal Energy Resources (Resource Management and Administration) Regulations

2015 (WA), r 16 1189 Petroleum and Geothermal Energy Resources (Resource Management and Administration) Regulations

2015 (WA), r 16 1190 Petroleum and Geothermal Energy Resources (Resource Management and Administration) Regulations

2015 (WA), r 17(1) and Schedule 1 1191 Ibid. 1192 Id at 16 1193 Ibid. 1194 Petroleum and Geothermal Energy Resources (Resource Management and Administration) Regulations

2015, Schedule 1, Item 14

174

principles, codes, standards and specifications and, if the activity relates to the exploration for

or recovery of petroleum, good oil-field practice.1195

A WMP must describe each well activity,1196 provide details of chemicals and other substances

that may be added or introduced in the course of well activity1197 and a list of the principal

Australian and international standards that apply to each well activity and plant used.1198 An

operator is required to control well integrity hazard (WIH) or risk.1199 These are events that

may compromise the integrity of a well, involve a risk of damage to an underground formation

that contains gas or an aquifer or any other part of the environment.1200 An operator must

describe how they will identify, monitor, mitigate and deal with a WIH and any increase in an

existing risk for the well, including the possibility of continuing a well activity for the purpose

of dealing with the WIH or the risk.1201 An offence is committed if a well is operated and a

WIH has been identified or there has been a significant increase in an existing risk for the

well.1202

FMPs must list the aquifers potentially affected by the development of the gas field and provide

a management proposal that includes baseline monitoring of groundwater sources.1203 They

must detail proposals for the enhanced recovery or recycling of petroleum; the processing,

storage or disposal of petroleum; the injection of water or treatment material into an

underground formation;1204 arrangements for the management of produced formation material

and waste fluid and other waste material produced from wells.1205

1195 Petroleum and Geothermal Energy Resources (Resource Management and Administration) Regulations

2015 Schedule 1, Item 4 1196 Petroleum and Geothermal Energy Resources (Resource Management and Administration) Regulations

2015 (WA), Schedule 1, Item 3 – Well management plan 1197 Petroleum and Geothermal Energy Resources (Resource Management and Administration) Regulations

2015 Schedule 1, Item 8 1198 Petroleum and Geothermal Energy Resources (Resource Management and Administration) Regulations

2015 Schedule 1, Item 14 1199 Petroleum and Geothermal Energy (Resource Management and Administration) Regulations 2015 (WA),

r 33 1200 Petroleum and Geothermal Energy (Resource Management and Administration) Regulations 2015 (WA),

r 4 1201 Ibid Schedule 1 r 7. 1202 Ibid r 33. 1203 Petroleum and Geothermal Energy Resources (Resource Management and Administration) Regulations

2015 (WA), Schedule 3, Item 8 1204 Petroleum and Geothermal Energy Resources (Resource Management and Administration) Regulations

2015 (WA), Schedule 3, Item 10 1205 Petroleum and Geothermal Energy Resources (Resource Management and Administration) Regulations

2015 (WA), Schedule 3, Item 14

175

Operators must submit daily activity reports that provide a summary of activities that are

carried out at the well including, but not limited to, details of chemicals used and stored onsite

and how deep the well has been drilled.1206 A FMP must detail the enhanced recovery or

recycling of petroleum; the processing, storage or disposal of petroleum; and the injection of

water or treatment material into an underground formation.1207

A WIH or risk1208 can affect well integrity. A WIH can involve a risk of damage to an

underground formation that contains gas; or an aquifer or any other part of the environment.1209

An operator must describe how they will identify, monitor, mitigate and deal with a WIH; and

any increase in an existing risk for the well, including the possibility of continuing a well

activity for the purpose of dealing with the WIH or the risk.1210 Western Australia’s chemical

disclosure obligations require operators to submit drilling fluid particulars as part of their

application to drill;1211 provide fluid information as part of their Well Completion Plan;1212

and for any approved petroleum activities, a summary of their approved EP, including all

chemicals likely to be used, which is publicly disclosed on the DMIRS website.

An operator must not recover gas unless they have an FMP in force or an approval under

regulation 59(1) of the Petroleum and Geothermal Energy Resources (Resource Management

and Administration) Regulations 2015, to recover gas without an approved FMP.1213 An FMP

must detail any aquifers that could be affected by the development of the field and the

applicant’s proposals for the management of such aquifers including proposals for baseline

1206 Petroleum and Geothermal Energy Resources (Resource Management and Administration) Regulations

2015 (WA), Schedule 5 e 1207 Petroleum and Geothermal Energy Resources (Resource Management and Administration) Regulations

2015 (WA), Schedule 3, Item 10

1208 Petroleum and Geothermal Energy (Resource Management and Administration) Regulations 2015 (WA), r

33 1209 Petroleum and Geothermal Energy (Resource Management and Administration) Regulations 2015 (WA),

r 4 1210 Ibid Schedule 1 r 7. 1211 Petroleum and Geothermal Energy Resources (Resource Management and Administration) Regulations

2015 (WA), Schedule 1, Item 8 1212 Petroleum and Geothermal Energy Resources (Resource Management and Administration) Regulations

2015 (WA), r 74 and Schedules 8 and 9 1213 Petroleum and Geothermal Energy Resources (Resource Management and Administration) Regulations

2015 (WA), r 41

176

monitoring1214 of groundwater sources, details of the operators proposals for the enhanced

recovery or recycling of petroleum, the processing, storage or disposal of petroleum, the

injection of water or treatment material into an underground formation1215 and descriptions of

the operators plans for decommissioning and rehabilitation.1216 Operators must submit daily

activity reports that provide a summary of any activity that is carried out at the well including,

but not limited to, details of chemicals used and stored onsite and how deep the well has been

drilled.1217

Wells are designed with layers of steel casing and cement that form a uninterrupted barrier

between the well and surrounding rock.1218 These designs meet pressure, temperature,

operational stresses and loads.1219 In South Australia, wells are pressure tested before hydraulic

fracturing and monitoring programs are in place i.e. well logs, pressure measurements, casing

integrity measurements and corrosion monitoring programs to determine the condition of

casing and cross flow behind casing.1220 The casing and cement is pressure tested to detect any

leaks before further steps are taken in the well construction process.1221 Evaluation tools are

used to assess the cement bond to confirm long term integrity of the well’s construction.1222

The whole process ‘is the subject of constant innovation by industry, is heavily regulated…and

requires that operators adhere to the highest well design standards, including ongoing

monitoring of the integrity of each barrier (casing strings) within the well bore’.1223

1214 Petroleum and Geothermal Energy Resources (Resource Management and Administration) Regulations

2015 (WA), Schedule 3, Item 8 1215 Petroleum and Geothermal Energy Resources (Resource Management and Administration) Regulations

2015 (WA), Schedule 3, Item 10 1216 Petroleum and Geothermal Energy Resources (Resource Management and Administration) Regulations

2015 (WA), Schedule 3, Item 16 1217 Petroleum and Geothermal Energy Resources (Resource Management and Administration) Regulations

2015 (WA), Schedule 5 1218 Energy Resources Division, Department of the Premier and Cabinet, South Australia, Gas and Oil in

Unconventional Reservoirs in the South East of South Australia, Version 27/07/17, pg 7

<https://petroluem.statedevelopment.sa.gov.au> 1219 Id at 5. 1220 Ibid. 1221 Id at 7. 1222 Ibid. 1223 Ibid.

177

4.3.3.1 Colorado

The COGCC requires operators to construct wells ‘with multiple layers of steel pipe (casing)

that are “telescoped” one inside the other, down the hole as it is deepened’.1224 The COGCC

insists that it undertakes pre and post construction wellbore reviews on every well permitted in

Colorado.1225 In Colorado, a pre-construction review of well casing and cement design is

carried out to verify that the wellbore will isolate fresh water from hydrocarbons.1226

The COGCC carries out field inspections on a number of wells to monitor drilling and

completion operations, including hydraulic fracturing.1227 Following well construction, the

COGCC reviews well log data, service reports, and daily field reports to confirm that casings

were installed pursuant to approved permits and COGCC rules and policies.1228

4.3.4 Underground injection

Underground injection is a fundamental part of hydraulic fracturing and waste water

disposal.1229 It is common practice for flow-back water to be reused in subsequent drilling and

hydraulic fracturing operations in the United States.1230 The recycling of drilling and hydraulic

fluids has not occurred in Western Australia to date given it has only been used on single,

1224 Colorado Oil & Gas Conservation Commission, Department of Natural Resources, Engineering Unit –

Well Bore Integrity, [DATE OR DATE VIEWED] at

<https://cogcc.state.co.us/documents/about/TF_Summaries/GovTaskForceSummary_Engineering%20Wellbor

e%20Integrity.pdf> 1225 Ibid. 1226 Ibid. 1227 Ibid. 1228 Ibid. 1229 Mark Zoback, Saya Kitasei, Brad Copithorne, Addressing the Environmental Risks for Shale Gas

Development, Briefing Paper 1, World Watch Institute, 2010, pg 9 at

<https://www.worldwatch.org/files/pdf/Hydraulic%20Fracturing%20Paper.pdf> 1230 Submission to the Legislative Council Standing Committee on Environment and Public Affairs, Parliament

of Western Australia, Inquiry into the Implications for Western Australia of Hydraulic Fracturing for

Unconventional Gas, Department of Mines and Petroleum, (2013) ,pg 15 at

http://www.parliament.wa.gov.au/Parliament/commit.nsf/(Evidence+Lookup+by+Com+ID)/C4EBD44EB7D2

9B4848257C40000F2471/$file/ev.fra.131003.sub.105.department+of+mines+and+petroleum.pdf

178

exploration well sites, though the DMIRS strongly advocates the treatment and re-use of water

on multiple well sites.1231

In the United States, a large amount of the hydraulic fracturing fluid is retrieved and placed in

evaporative pits and re-used in other operations or disposed of in surface waters, underground

reservoirs, or at treatment facilities.1232 The fluid comprises water (99 percent), sand and

chemical additives.1233 Managing it correctly is key to protecting the environment when it

comes to the production of shale and tight gas.1234 Produced water has the capacity to

supplement conventional water supplies if handled as a resource rather than a waste product.1235

The disclosure of hydraulic fracturing fluid additives is an important issue which jurisdictions

address through legislation to varying degrees.1236 The treatment and disposal of waste water

is a critical issue where hydraulic fracturing is used1237 and there are different options that

should be considered.1238

Underground injection and/or re-injection commonly occurs when ‘injection zones’ are

available.1239 To avoid groundwater degradation in aquifers, reinjection is not permitted.1240

Reinjecting produced water into gas formations does not pose additional risks to underground

aquifers, though reinjection into aquifers may affect groundwater quality.1241 Produced water

1231 Ibid. 1232 James G. Speight, Shale Gas Production Processes, Gulf Professional Publishing, 2013, pg 141 1233 Energy.Gov, Office of Fossil Energy, (United States), Shale Gas 101, ‘Aren’t shale fracturing fluids

toxic?’, (accessed 19 June 2017) at https://www.energy.gov/fe/shale-gas-101#faq_7 1234 Ibid. 1235 Katie Guerra, Katherine Dahm & Steve Dundorf, Oil and Gas Produced Water Management and Beneficial

Use in the Western United States, Science and Technology Program Report No. 157, U.S. Department of the

Interior, Bureau of Reclamation, 2011, pg 2 at

<https://www.usbr.gov/research/AWT/reportpdfs/report157.pdf> 1236 Energy.Gov, Office of Fossil Energy, (United States), Shale Gas 101, ‘Aren’t shale fracturing fluids

toxic?’, (accessed 19 June 2017) at <https://www.energy.gov/fe/shale-gas-101#faq_7 1237 World Energy Outlook, Golden Rules for Golden Age of Gas, World Energy Outlook Special Report on

Unconventional Gas, (2012) , pg 32 at

http://www.worldenergyoutlook.org/media/weowebsite/2012/goldenrules/weo2012_goldenrulesreport.pdf 1238 Id at 33. 1239 Department of Mines and Petroleum, Submission to the Legislative Council Standing Committee on

Environment and Public Affairs, Parliament of Western Australia, ‘Inquiry into the Implications for Western

Australia of Hydraulic Fracturing for Unconventional Gas, October 2013, pg 15 at

http://www.parliament.wa.gov.au/Parliament/commit.nsf/(Evidence+Lookup+by+Com+ID)/C4EBD44EB7D2

9B4848257C40000F2471/$file/ev.fra.131003.sub.105.department+of+mines+and+petroleum.pdf 1240 Ibid. 1241 Standing Committee on Environment and Public Affairs, Parliament of Western Australia Report 42,

Inquiry into the Implications for Western Australia of Hydraulic Fracturing for Unconventional Gas, pg 125 at

<

http://www.parliament.wa.gov.au/Parliament/commit.nsf/(Report+Lookup+by+Com+ID)/74E61E739E39E57

748257EF9002150FE/$file/ev.fra.151117.rpf.042.xx.pdf>

179

must be treated prior to injection if it is not of the same quality as the aquifer to ensure that its

water quality is not compromised.1242 There must be a porous and permeable formation capable

of receiving injected fluids in close proximity to the gas field.1243

Where local sites are not available, waste water in the United States is often transported to other

locations or treated through either self-contained systems at well sites or fields, or through

community waste water treatment plants or commercial treatment facilities.1244 An operator’s

ability to transport waste to treatment plants may be restricted to large urban centres with

treatment plants with limited capacity.1245 Underground injection and transportation

to treatment facilities may or may not be practical1246

Generally speaking, there is little risk of fracking chemicals and produced water contaminating

aquifers1247 given that gas tends to be well below the depth of potable aquifers and that shales

act as aquitards1248 (a zone that restricts the flow of groundwater). Potential contamination can

result from well failure, stimulating fractures/faults and poor handling of produced water.1249

4.3.4.1 Western Australia and South Australia

The DMIRS and DoWER regulate hydraulic fracture wastewater where it is linked to a

prescribed premises licensed under the Environmental Protection Act 1986 (WA). The waste

may be disposed of by storing it in evaporation ponds (lined with strong plastic used to hold

flowback fluids or produced formation water) or underground by injecting into deep porous

rock formations.1250

1242 Ibid 1243 J. Daniel Arthur, Bruce Langhus, David Alleman, ALL Consulting, An Overview of Modern Shale Gas

Development in the United States, 2008, pg 21 at <http://www.all-

llc.com/publicdownloads/ALLShaleOverviewFINAL.pdf> 1244 Ibid. 1245 Ibid. 1246 Ibid. 1247 Australian Council of Learned Academies, Potential Geological Risks Associated with Shale Gas

Production in Australia, January 2013, pg 4 at

<http://www.acola.org.au/PDF/SAF06FINAL/Frogtech_Shale_Gas_Geology_and_Risks%20Jan2013.pdf> 1248 Ibid. 1249 Ibid. 1250 Department of Mines, Industry Regulation and Safety, Guide to the Regulatory Framework for Shale and

Tight Gas in Western Australia, A Whole of Government Approach, 2015 Edition, pg 31,

http://www.dmp.wa.gov.au/Documents/Petroleum/WEB_Shale_and_Tight_Gas_Framework.pdf

180

The disposal method must be set out in an operator’s EP and submitted to the DMIRS before

commencement of any petroleum activities. The DoWER ensures safe disposal by licencing

carriers, drivers and vehicles involved in public road transportation under the Environmental

Protection (Controlled Waste) Regulations 2004 (WA). DMIRS regulates the injection or re-

injection through the Petroleum and Geothermal Energy Resources (Environment) Regulations

2012 (WA).

Where an activity involves the injection or re-injection of produced formation water into wells

in Western Australia, the EP implementation strategy must specify the maximum permissible

concentration of petroleum in the water.1251 An operator must ensure that the concentration of

petroleum in any produced formation water does not exceed the specified concentration.1252

The Minister must not give consent unless the operator demonstrates, to the satisfaction of the

Minister, that the proposed discharge, injection or re-injection will not result in the occurrence

of any significant new environmental impact or environmental risk, or a significant increase in

any existing environmental impact or environmental risk.1253 A geothermal energy recovery

development plan must detail the enhanced recovery or recycling of produced formation

material; the processing, storage or disposal of produced formation material; and the injection

of water or treatment material into an underground formation.1254 Proposals must detail how

waste water will be treated, reused and disposed of1255 and operators are encouraged to reuse

fracking fluid where possible.1256

A petroleum production licence in South Australia authorises an operator to carry out

injection.1257 An operator who drills a well must assess the geology through which the well

passes, and the prospect of gas for which the licence is held in accordance with good industry

1251 Petroleum and Geothermal Energy Resources (Environment) Regulations 2012 (WA), r 15(8) 1252 Petroleum and Geothermal Energy Resources (Environment) Regulations 2012 (WA), r 33(1) 1253 Petroleum and Geothermal Energy Resources (Environment) Regulations 2012 (WA), r 33(5) 1254 Petroleum and Geothermal Energy Resources (Resource Management and Administration) Regulations

2015 (WA), Schedule 4, Item 10 1255 Department of Mines, Industry Regulation and Safety, Natural Gas from Shale and Tight Rocks An

overview of Western Australia’s regulatory framework February 2014, pg 8 at

http://www.DMIRS.wa.gov.au/Documents/Petroleum/PD-SBD-NST-102D.pdf 1256 Ibid. 1257 Petroleum and Geothermal Energy Act (SA), s 34(2)(a)(i)

181

practice and in accordance with the Petroleum and Geothermal Energy Regulations 2013

(SA).1258

An operator must provide a daily drilling report which includes information on operations

carried out during the reporting period, a description of the formations, and the depth of any

geological formation tops encountered during the reporting period and also well logs acquired

during the reporting period.1259 If an operator undertakes drilling they must provide a well

completion report.1260

4.3.5 Chemical disclosure

Around 23 states in the United States, including Colorado, use FracFocus to publicly

disclose1261 the composition of hydraulic fracturing fluids, including the chemicals used.1262

FracFocus is a web-based register managed by the Ground Water Protection Council1263 and

the Interstate Oil and Gas Compact Commission1264 that provides information on hydraulic

fracturing fluid products, including trade name, supplier, purpose and composition.1265

Services providers and vendors in Colorado who provide hydraulic fracturing additives must

provide an operator with the total volume of water used in the hydraulic fracturing treatment

of the well or the type and total volume of the base fluid used in the hydraulic fracturing

treatment, if something other than water; each hydraulic fracturing additive used in the

hydraulic fracturing fluid and the trade name, vendor, and a brief descriptor of the intended use

or function of each hydraulic fracturing additive in the hydraulic fracturing fluid; each chemical

intentionally added to the base fluid; the maximum concentration, in percent by mass, of each

1258 Petroleum and Geothermal Energy Regulations 2013 (SA), s 27 1259 Petroleum and Geothermal Energy Regulations 2013 (SA), s 38(3) 1260 Petroleum and Geothermal Energy Regulations 2013 (SA), s 40 1261 Chemical Disclosure Registry, Colorado Rules and Regulations, Definitions 100 Series, pg 100-2, 2016 at

https://cogcc.state.co.us/documents/reg/Rules/LATEST/CompleteRules%20as%20of%20March%2016,%2020

16.pdf 1262 Frac Focus Chemical Disclosure Registry, (accessed 18 June 2017) at <http://fracfocus.org/> 1263 Groundwater Protection Council, (accessed (accessed 19 June 2017) at <http://www.gwpc.org/> 1264 Interstate Oil & Gas Compact Commission, (accessed 19 June 2017) at <http://iogcc.publishpath.com/> 1265 Frac Focus Chemical Disclosure Registry, (accessed 18 June 2017) at <http://fracfocus.org/>

182

chemical intentionally added to the base fluid; and the chemical abstract service number for

each chemical intentionally added to the base fluid, if applicable.1266

Western Australia has a ‘system-based’ chemical disclosure approach that sanctions public

disclosure of chemicals while providing protection of manufacturer’s products.1267 In Western

Australia, a WMP must include details of chemicals and other substances that may be — (a)

in, or added to, treatment materials to be used for the purposes of drilling or hydraulic fracturing

undertaken in the course of each well activity; or (b) otherwise introduced into a well or

underground formation in the course of each well activity; or (c) otherwise used in the course

of each well activity.1268 Daily well activity reports must provide details of chemicals or other

substances kept on site for use in the well activity.1269

The disclosure of chemicals in Western Australia is to the DMIRS, not to the public, which

facilitates disclosure without compromising commercially sensitive information about product

recipes.1270 The information must also be submitted to the DMIRS as part of the summary EP,

which is then made publicly available.1271 This thesis provides guarded support to Western

Australia’s chemical disclosure obligations which require operators to submit information to

the DMIRS. Western Australia’s system sanctions public disclosure while protecting

manufacturers. The disclosure is to the DMIRS not directly to the public.

The COGCC requires operators to maintain a chemical inventory, disclose certain information

and take precautions to keep wells under control. This thesis favours Colorado’s chemical

1266 COGCC rules 205A.b.(2)(A)(viii) – (xii) s 1267 Letter from Hon Bill Marmion MLA, Minister for Mines and Petroleum, 14 April 2015, p 4 to the

Standing Committee on Environment and Public Affairs, Parliament of Western Australia, Implications for

Western Australia of Hydraulic Fracturing for Unconventional Gas, November 2015, pg 87 at

<https://www.parliament.wa.gov.au/Parliament/commit.nsf/(Report+Lookup+by+Com+ID)/74E61E739E39E5

7748257EF9002150FE/$file/ev.fra.151117.rpf.042.xx.pdf> 1268 Petroleum and Geothermal Energy Resources (Resource Management and Administration) Regulations

2015 (WA), Schedule 1, Item 8 1269 Petroleum and Geothermal Energy Resources (Resource Management and Administration) Regulations

2015 (WA), Schedule 5, Item 21 1270 Submission 105 from Department of Mines and Petroleum, to the Standing Committee on Environment

and Public Affairs Inquiry into the Implications for Western Australia of Hydraulic Fracturing for

Unconventional Gas, 3 October 2013, pg 11 at

http://www.parliament.wa.gov.au/Parliament/commit.nsf/(Evidence+Lookup+by+Com+ID)/C4EBD44EB7D2

9B4848257C40000F2471/$file/ev.fra.131003.sub.105.department+of+mines+and+petroleum.pdfhttp://www.p

arliament.wa.gov.au/Parliament/commit.nsf/(Evidence+Lookup+by+Com+ID)/C4EBD44EB7D29B4848257C

40000F2471/$file/ev.fra.131003.sub.105.department+of+mines+and+petroleum.pdf

The exact chemical recipe for a product is not disclosed, only the chemicals that may be mixed together to

form the product (such as drilling muds or fracturing fluids). 1271 Ibid.

183

disclosure system where operators complete a simple chemical disclosure registry form and

upload it onto the chemical disclosure registry (FracFocus). This thesis favours Colorado’s

system where operators must submit chemical disclosure forms within 60 days of the

conclusion of fracking. An operator who claims that the identity or concentration of a chemical

is a trade secret does not need to disclose them on their disclosure form, though the information

must be provided to the COGCC if it is requested.

Any information that is posted to the site or sent to the COGCC (unless a trade secret) is public

information. The COGCC and the public can search for information by geographic area,

ingredient, chemical abstract service number, time period, and operator. The thesis supports

Colorado’s preliminary baseline sampling and subsequent monitoring where all available water

sources within a one-half mile radius of a proposed gas well, multi-well site, or dedicated

injection well. Subsequent sampling is carried out at the initial sample locations between six

and 12 months, and a second subsequent sampling is conducted between 60 and 72 months

following completion of the well or dedicated injection well, or the last well on a multi-well

site.1272

Regulation 83 provides a definition of permanently confidential information. Regulation 83(4)

and 83(5) set out the circumstances where documentary information given by a person to the

Minister is considered to be permanently confidential information. For example, information

is considered permanently confidential if, when it was given the Minister was advised in

writing that the person classified the information as a trade secret; or information the disclosure

of which would, or could reasonably be expected to, adversely affect the person’s business,

commercial or financial affairs and the Minister did not give the person a written notice.

This thesis supports the deletion of regulation 83 of the Petroleum and Geothermal Energy

Resources (Resource Management and Administration) Regulations 2015, as recommended by

the Standing Committee on Environment and Public Affairs. The Standing Committee on

Environment and Public Affairs determined that regulation 83 does not, in their opinion, meet

1272 COGCC rule 609 at

https://cogcc.state.co.us/documents/reg/Rules/LATEST/Complete%20Rules%20as%20of%20May%201,%202

018.pdf>

184

the DMIRS’s stated intention of transparency in relation hydraulic fracturing and the public.1273

The Committee recommended that regulation 83 be amended and, specifically, that regulations

83(4) and 83(5) be deleted.1274

Halliburton Australia, who support disclosure to FracFocus, recently suggested two

alternatives to full public disclosure, namely i) a procedure that disclosures hydraulic fracturing

ingredients and maximum concentrations on a well-by-well basis; or ii) disclosure to the

National Industrial Chemicals Notification and Assessment Scheme (NICNAS) with patented

information protected from public release.1275

Santos Limited, who supports FracFocus disclosure, deem that full disclosure of certain

chemicals should be protected given that full disclosure may curtail the use of new, innovative

and environmentally benign products.1276 AWE Limited is concerned about theDMIRS’s

Chemical Disclosure Guideline1277 and deem that disclosure may lead some third-party

contractors to withhold their products from the Western Australian hydraulic fracturing market

due to sensitivities surrounding the release of chemical compounds.1278

Operators must retain appropriate operational records to enable them to make and substantiate

reports required by the COGCC.1279 Operators must submit chemical disclosure forms within

1273 Report 42, Standing Committee on Environment and Public Affairs, Parliament of Western Australia,

Implications for Western Australia of Hydraulic Fracturing for Unconventional Gas, November 2015, pg 43 at

<

http://www.parliament.wa.gov.au/Parliament/commit.nsf/(Report+Lookup+by+Com+ID)/74E61E739E39E5774

8257EF9002150FE/$file/ev.fra.151117.rpf.042.xx.pdf> 1274 Ibid. 1275 Halliburton Australia Pty Ltd, Submission to the Inquiry into the Implications for Western Australia of

Hydraulic Fracturing for Unconventional Gas, 4 October 2013, pp 4-55 at <

http://www.parliament.wa.gov.au/Parliament/commit.nsf/(Evidence+Lookup+by+Com+ID)/570201DA298F6

6B048257C40000F617F/$file/ev.fra.131004.sub.106.halliburton.pdf> 1276 Santos Limited, Submission to the Inquiry into the Implications for Western Australia of Hydraulic

Fracturing for Unconventional Gas, 4 October 2013, p 10 at <

http://www.parliament.wa.gov.au/Parliament/commit.nsf/(Evidence+Lookup+by+Com+ID)/A01ABCA4A181

C60C48257C40000FF3A8/$file/ev.fra.131004.sub.109.santos+ltd.pdf> 1277 Department of Mines, Industry Regulation and Safety (WA), Chemical Disclosure Guideline, 2013 at <

http://www.dmp.wa.gov.au/Documents/Environment/ENV-PEB-178.pdf> 1278 Submission 113 from AWE Limited, Submission to the Inquiry into the Implications for Western Australia

of Hydraulic Fracturing for Unconventional Gas, 7 October 2013, p 25 at <

http://www.parliament.wa.gov.au/Parliament/commit.nsf/(Evidence+Lookup+by+Com+ID)/34B73EFE03658

12B48257C4000115456/$file/ev.fra.131007.sub.113.awe+limited.pdf> 1279 COGCC rule 205. a, Access to Records at <

https://cogcc.state.co.us/documents/reg/Rules/LATEST/Complete%20Rules%20as%20of%20May%201,%202

018.pdf>

185

60 days of the conclusion of fracking.1280 An operator who claims that the identity or

concentration of a chemical is a trade secret does not need to disclose them on their disclosure

form though the information must be provided to the COGCC if it is requested.1281

Operators must give at least 48 hours advanced written notice to the COGCC prior to

undertaking hydraulic fracturing1282 and continuously monitor and record well pressure

between the intermediate casing and the production casing to ensure that fracking fluids are

restricted to the targeted formations.1283 An operator must notify the COGCC if they observe

changes in well pressure and indicate that fluid is leaking from the well.1284 Operators are

required to carry out baseline and post-completion surface water sampling where fracking

occurs in a Surface Water Supply Area1285 and in relation to green well completions1286 to reduce

harmful air emissions.

An operator must not dispose of water underground or commence construction of a well for

the purpose of underground injection without having first received written authorisation from

the COGCC.1287 An operator must submit an Underground Injection Formation Permit

Application, Form 311288 and an Injection Well Permit Application, Form 33.1289 If an operator

intends to drill a disposal well they must also submit (concurrently) an Application for Permit-

1280 COGCC rule 205A, Hydraulic Fracturing Chemical Disclosure at

<https://cogcc.state.co.us/Announcements/Hot_Topics/Hydraulic_Fracturing/Rule205A.pdf> 1281 Ibid. 1282 COGCC rule 316C at

https://cogcc.state.co.us/documents/reg/Rules/LATEST/Complete%20Rules%20as%20of%20May%201,%202

018.pdf> 1283 COGCC rule 341 at

https://cogcc.state.co.us/documents/reg/Rules/LATEST/Complete%20Rules%20as%20of%20May%201,%202

018.pdf> 1284 Ibid. 1285 COGCC rule 317B at

https://cogcc.state.co.us/documents/reg/Rules/LATEST/Complete%20Rules%20as%20of%20May%201,%202

018.pdf> 1286 COGCC rule 805 at

https://cogcc.state.co.us/documents/reg/Rules/LATEST/Complete%20Rules%20as%20of%20May%201,%202

018.pdf> 1287 COGCC rule 325 a. 1288 COGCC Form 31, Underground Injection Formation Permit Application at

<https://cogcc.state.co.us/documents/reg/Forms/PDF_Forms/form31.pdf> 1289 Form 33, Injection Well Permit Application at

<https://cogcc.state.co.us/documents/reg/Forms/PDF_Forms/form33.pdf>

186

to-Drill, Form 2,1290 along with a service and filing fee1291 The COGCC may refuse to issue a

permit and approve underground injection if it considers that the disposal well could result in

a significant adverse impact on the environment.1292

Colorado is at the forefront of gas regulation in the United States given it has, amongst other

things, a detailed drilling and well site activities regime and specific environmental regulations

to manage water.1293 In Western Australia, an operator may carry out drilling and injection

activities into natural reservoirs to enhance gas production.1294 The grant of a production

licence authorises an operator to undertake injection1295 and, if they drill a well, they must assess

the geology the well passes through and the prospectivity of gas in accordance with good

industry practice.1296

Operators in Colorado must provide landowners with a notice of intent to carry out hydraulic

fracturing.1297 They must give at least 48 hours advance notice to the COGCC of a hydraulic

fracturing treatment.1298 The COGCC requires operators to maintain a chemical inventory,1299

disclose certain information1300 and take precautions to keep wells under control.1301 The

COGCC rules require operators to have well setbacks and take precautions near surface waters

1290 COGCC Form 2, Application for Permit to: at

<https://cogcc.state.co.us/documents/reg/Forms/PDF_Forms/form2_20130806.pdf> 1291 COGCC rule 325 at

https://cogcc.state.co.us/documents/reg/Rules/LATEST/Complete%20Rules%20as%20of%20May%201,%202

018.pdf> 1292 COGCC rule 325 b. 1293 Stephanie Neitzel, P.E. Esq. Principal WaterRich Advisors LLC, Centennial, Colorado, Water Quality

Regulations for Unconventional Gas Production, United States and Australia Comparison, pg 4 at <

http://www.awa.asn.au/documents/136%20SNeitzel.pdf> 1294 Petroleum and Geothermal Energy Act 2000 (SA), s 10(3)(b)(c) 1295 Section 34(2)(a)(i) of the PGE Act 1296 Petroleum and Geothermal Energy Regulations 2013 (SA), r 27 1297 COGCC rule 305.e.e(1)A at

https://cogcc.state.co.us/documents/reg/Rules/LATEST/Complete%20Rules%20as%20of%20May%201,%202

018.pdf> 1298 COGCC rule 316C at

https://cogcc.state.co.us/documents/reg/Rules/LATEST/Complete%20Rules%20as%20of%20May%201,%202

018.pdf> 1299 COGCC rule 205 at

https://cogcc.state.co.us/documents/reg/Rules/LATEST/Complete%20Rules%20as%20of%20May%201,%202

018.pdf> 1300 COGCC rule 205A at

https://cogcc.state.co.us/documents/reg/Rules/LATEST/Complete%20Rules%20as%20of%20May%201,%202

018.pdf> 1301 COGCC rule 317 at

https://cogcc.state.co.us/documents/reg/Rules/LATEST/Complete%20Rules%20as%20of%20May%201,%202

018.pdf>

187

used for drinking.1302 Operators must monitor bradenhead pressure during well stimulation

operations.1303 There are detailed pit permitting and reporting requirements1304 and pit lining

requirements and specifications contained in the COGCC rules.1305 The COGCC rules require

that spills and releases be reported to the COGCC, CDPHE and the landowner.1306

An operator must prepare and submit a daily drilling report that specifies, amongst other things,

the depth of the well at the end of the reporting period; the operations carried out during the

reporting period; resource descriptions; a description of the formations; and the depth of any

geological formation tops encountered during the reporting period.1307 An operator who

undertakes drilling must provide a well completion report in accordance with the requirements

of these regulations. A well completion report must include the name and number of the well

and a summary page or pages, located at the beginning of the report, which sets out in concise

form basic information relating to the well found in the report.1308

In Colorado, COGCC rule 1002.d states that:

The drilling location shall be designed and constructed to provide a safe

working area while reasonably minimizing the total surface area

disturbed.1309

1302 COGCC rule 317B at

https://cogcc.state.co.us/documents/reg/Rules/LATEST/Complete%20Rules%20as%20of%20May%201,%202

018.pdf> 1303 COGCC rule 341 at

https://cogcc.state.co.us/documents/reg/Rules/LATEST/Complete%20Rules%20as%20of%20May%201,%202

018.pdf> 1304 COGCC rule 903 at

https://cogcc.state.co.us/documents/reg/Rules/LATEST/Complete%20Rules%20as%20of%20May%201,%202

018.pdf> 1305 COGCC rule 904 at

https://cogcc.state.co.us/documents/reg/Rules/LATEST/Complete%20Rules%20as%20of%20May%201,%202

018.pdf> 1306 COGCC rule 906 at

https://cogcc.state.co.us/documents/reg/Rules/LATEST/Complete%20Rules%20as%20of%20May%201,%202

018.pdf> 1307 Petroleum and Geothermal Energy Regulations 2013 (SA), r 38 1308 Petroleum and Geothermal Energy Regulations 2013 (SA), r 40 1309 COGCC rule 1002(d) at

https://cogcc.state.co.us/documents/reg/Rules/LATEST/Complete%20Rules%20as%20of%20May%201,%202

018.pdf>

188

At the conclusion of hydraulic fracturing in Colorado operators must complete a chemical

disclosure registry form and post it on the chemical disclosure registry.1310 Any information

received by the COGCC or posted to the registry (unless a trade secret) is public

information.1311 The COGCC and the public can search for information by geographic area,

ingredient, chemical abstract service number, time period, and operator.1312

4.3.6 Conclusion

The author favour the implementation of pre and post construction wellbore reviews on wells

permitted in Western Australia and South Australia. In Colorado, pre-construction reviews are

carried out to verify that the wellbore will isolate fresh water from hydrocarbons. The author

supports field inspections to monitor drilling and completion operations, including hydraulic

fracturing. Once wells are constructed operators should provide the DMIRS and the DPC with

well log data, service reports, and daily field reports to confirm that casings were installed

pursuant to approved permits, rules and policies.

Operators should be required to provide daily drilling reports that include information on

operations carried out during the reporting period, a description of the formations, and the depth

of any geological formation tops encountered during the reporting period and also well logs

acquired during the reporting period. Operators should be required to retain appropriate

operational records to enable them to make and substantiate reports required by regulators and

submit chemical disclosure forms within a specified time after the conclusion of hydraulic

fracturing.

The author favours the implementation of Underground Injection Formation Permit

Application and Injection Well Permit Application processes to manage the

injection/reinjection of wastewater.

1310 COGCC rule 205(b)(2)(A) at

https://cogcc.state.co.us/documents/reg/Rules/LATEST/Complete%20Rules%20as%20of%20May%201,%202

018.pdf> 1311 COGCC rule 205(2)(D) at

https://cogcc.state.co.us/documents/reg/Rules/LATEST/Complete%20Rules%20as%20of%20May%201,%202

018.pdf> 1312 COGCC rule 205A(3) at

https://cogcc.state.co.us/documents/reg/Rules/LATEST/Complete%20Rules%20as%20of%20May%201,%202

018.pdf>

189

4.4 Decommissioning and rehabilitation

The practice of safely decommissioning a well, dismantling facilities and rehabilitating

land to its natural state or some other form desired by society has been common practice

in the petroleum industry for many decades and the industry has developed state-of-the-

art skills in performing this function.1313

Western Australia considers decommissioning a petroleum activity under the PGERA

Environment Regulations. By comparison, the PGEA does not consider decommissioning,

abandonment and rehabilitation regulated activities.1314 There are no specific legislative

provisions in the PGERA or PGEA that require operators to carry out specific

decommissioning and rehabilitation in a particular way.

The PGERA and PGEA do not treat abandonment and reclamation in the same way as the

OGCA. They are not considered petroleum operations under the PGERA or regulated activities

under the PGEA. They are considered oil and gas operations under the OGCA. The PGERA

does refer to decommissioning and rehabilitation and the PGEA to decommissioning,

abandonment and rehabilitation. The COGCC rules deal extensively with abandonment and

reclamation.

In Western Australia, environmental plans contain well abandonment and decommissioning

information, field closure plans and details about rehabilitation. In these documents, operators

describe their plans for field closure. They are also required to submit final well activity reports

which includes the status of wells, i.e., whether they are producing, suspended or

decommissioned and if applicable, information on cementing operations and schematics of

decommissioning. A well completion form1315 is also required that includes the status of a

1313 Parliamentary Inquiry into the Implications for Western Australia of Hydraulic Fracturing for

Unconventional Gas, Submission for the Chamber of Minerals and Energy Western Australia, September

2013, pg 38 at

http://www.parliament.wa.gov.au/Parliament/commit.nsf/(Evidence+Lookup+by+Com+ID)/99D8D0023E339

C6F48257C4000110456/$file/ev.fra.131004.sub.112.the+chamber+of+minerals+and+energy+of+western+aus

tralia.pdf 1314 Petroleum and Geothermal Energy Act 2000 (SA), s 10 1315 Petroleum and Geothermal Energy Resources (Resource Management and Administration) Regulations

2015 (WA), r 74(1)

190

well1316 and (if applicable) information on cementing operations and schematics of

decommissioning.1317

In South Australia, the DPC must be advised of an operator’s intentions with respect to

decommissioning, abandonment and rehabilitation. Operators must provide specific details of

well completion or abandonment. The term of an associated activities licence for regulated

activities may take may take into account any decommissioning, rehabilitation or other action

that may be required at the conclusion of the activities.

When compared to the COGCC rules, the PGERA and PGEA regulations are lacking. In

Colorado, details of proposed abandonment operations must be provided to the COGCC. As

is the case under the PGERA and PGEA, operators in Colorado must also provide a current

wellbore diagram and a wellbore diagram showing the proposed plugging procedure.

There are no specific provisions in the PGERA or PGEA that deal with the relationship between

landowners and operators with respect to decommissioning and rehabilitation. In Colorado,

operators must use their best efforts to consult in good faith with surface owners, which give

surface owners the chance to provide feedback on the timing of operations and on final

reclamation, including the desired final land use and seed mix to be applied. An operator who

wishes to abandon a well in Colorado must comply with specific regulatory requirements,

contractual obligations, and lessor and landowner requirements. There are no lessor and

landowner requirements in the PGERA or PGEA.

Another issue not contemplated in the PGERA or PGEA relates to the exploitation of wells by

landowners. In Colorado, if a landowner wishes to exploit a well for fresh water, the well does

not require filling above the required sealing plug set below the fresh water; provided the

landowner has given written authority and assumes responsibility to plug the well upon its

abandonment.1318 A well may be temporarily abandoned if it is cased or left in a way that

1316 Petroleum and Geothermal Energy Resources (Resource Management and Administration) Regulations

2015 (WA), Schedule 9, Item 6 1317 Petroleum and Geothermal Energy Resources (Resource Management and Administration) Regulations

2015 (WA), Schedule 9, Item 30 1318 COGCC rule 319(a)(7) at

https://cogcc.state.co.us/documents/reg/Rules/LATEST/Complete%20Rules%20as%20of%20May%201,%202

018.pdf>

191

prevents migration of gas, water or other substance from its original formation or horizon.1319

An application to temporarily abandon a well must advise why the well is being temporarily

abandoned and future plans for its use.1320

The COGCC rules require operators to submit three very straight forward reports. These are

the well abandonment report, notice of intent to abandon report and subsequent report of

abandonment. The PGERA and PGEA are silent on the protection of fresh water strata in terms

of decommissioning and rehabilitation. The COGCC must authorise the removal of surface

casing from wells COGCC. The COGCC must approve the plugging method and be advised

of the estimated time and date of plugging and identify the depth and thickness of all known

sources of groundwater.1321 Within three months of plugging a well in Colorado, operators

must back fill all pits, mouse and rat holes and cellars and the remove all waste. They must

abandon gathering line risers, flowline risers, and surface equipment. Operators close, grade

and re-contour all access roads to plugged and abandoned wells and related production

facilities.

The COGCC rules explicitly state that surface land must be restored to the condition it was at

the start of the drilling operation. Disturbed areas no longer needed must be restored and

revegetated as soon as practicable. The COGCC rules set out that operators should locate,

construct and maintain well sites, production facilities, gathering pipelines, and access roads

(unless they already have access roads) to satisfactorily control dust and minimise erosion,

alteration of natural features, remove surface materials, and degradation due to

contamination.1322 Those areas affected by drilling or subsequent operations, excluding those

that are needed for production purposes or for subsequent drilling operations commencing

within twelve months, must be reclaimed to their previous condition or in a way that makes

them suitable for their final land use as chosen by the landowner and must be maintained to

control dust and minimise erosion to a level that is practicable.1323

1319 COGCC rule 319(b)(1) at

<https://cogcc.state.co.us/documents/reg/Rules/LATEST/Complete%20Rules%20as%20of%20May%201,%20

2018.pdf> 1320 COGCC rule 319(b)(3) at

<https://cogcc.state.co.us/documents/reg/Rules/LATEST/Complete%20Rules%20as%20of%20May%201,%20

2018.pdf> 1321 COGCC rule 319(a)(6) at <https://cogcc.state.co.us/documents/reg/Rules/LATEST/300Series.pdf> 1322 COGCC rule 1001(e)(1) at <https://cogcc.state.co.us/documents/reg/Rules/LATEST/1000Series.pdf> 1323 COGCC rule 1003(b) at <https://cogcc.state.co.us/documents/reg/Rules/LATEST/1000Series.pdf>

192

4.4.1 Western Australia - FMP, WMP and EP

The PGERA refers to ‘decommissioning and rehabilitation’.1324 In Western Australia, an

operator must remove all property brought into that area by any person engaged or concerned

in the operations, to plug or close off wells, to make provision for the conservation and

protection of the natural resources and to make good damage to the Earth’s crust in that area

caused by any person engaged or concerned in those operations.1325

Decommissioning and rehabilitation in Western Australia are carried out in accordance with a

FMP, WMP and EP.1326 Wells that are considered non-productive and those that have been

completely exploited must be plugged, sealed, decommissioned and sites rehabilitated.1327

Decommissioning involves the removal of infrastructure; equipment; fuel, chemical and

hazardous materials, and the treatment of residual drill cuttings piles and naturally occurring

radioactive minerals.1328 Rehabilitation involves the removal of soil and cuttings stockpiles,

sumps and fluid ponds, soil re-contouring and stabilisation, re-vegetation of cleared areas, weed

control and removal and disposal of waste (food scraps, concrete, plastic packaging, septic

waste, tyres, scrap metals, liquid wastes and hazardous wastes).1329

Western Australian operators must manage well abandonment and include specific details in

the EPs they submit to the DMIRS1330 and must monitor the rehabilitation activities carried out

on a production site for an appropriate period of time after decommissioning before their

licence can be surrendered.1331 An EP must summarise the rehabilitation activities that an

1324 Petroleum and Geothermal Energy Resources (Resource Management and Administration) Regulations

2015 (WA) and Petroleum and Geothermal Energy Resources (Environment) Regulations 2012 (WA) 1325 Section 101 of the PGERA 1326 Petroleum and Geothermal Energy Resources (Environment) Regulations 2012 (WA) Part 2 1327 Department of Mines, Industry Regulation and Safety, Guide to the Regulatory Framework for Shale and

Tight Gas in WA, A Whole of Government Approach, 2015 Edition, pg 21 at

<https://www.DMIRS.wa.gov.au/Documents/Petroleum/WEB_Shale_and_Tight_Gas_Framework.pdf> 1328 Submission to the Legislative Council Standing Committee on Environment and Public Affairs, Parliament

of Western Australia, Inquiry into the Implications for Western Australia of Hydraulic Fracturing for

Unconventional Gas, Department of Mines and Petroleum 2013, p 17 at

<http://www.parliament.wa.gov.au/Parliament/commit.nsf/(Evidence+Lookup+by+Com+ID)/C4EBD44EB7D

29B4848257C40000F2471/$file/ev.fra.131003.sub.105.department+of+mines+and+petroleum.pdf> 1329 Id at 16. 1330 Petroleum and Geothermal Energy Resources (Environment) Regulations 2012 (WA) Part 2 1331 Department of Mines, Industry Regulation and Safety, Guide to the Regulatory Framework for Shale and

Tight Gas in WA, A Whole of Government Approach, 2015 Edition, pg 21 at

<http://www.DMIRS.wa.gov.au/Documents/Petroleum/WEB_Shale_and_Tight_Gas_Framework.pdf>

193

operator intends to carry out and their objectives and commitment for the areas impacted by

proposed activities.1332

EPs must address decommissioning and rehabilitation and include a safety management

system/safety case.1333 For example, the Canning Basin EP1334 states that where there are no

signs of gas, a well will be plugged and abandoned by putting cement plugs in the open hole

and at the surface.1335 The rehabilitation of access tracks, well sites and camps must commence

within three months of plugging and abandonment.1336 The Canning Basin JV EP1337 states

that at the completion of drilling, a well will be suspended or plugged and abandoned.1338 Well

sites will also be demobilised in accordance with the EP.1339 Within a year of plugging and

abandoning a well, rehabilitation must commence in accordance with rehabilitation

standards.1340 The DMIRS carries out inspections to determine compliance against approved

EPs.1341 If decommissioning is not adequately explained in the EP that has been approved by

the DMIRS, the operator must include a commitment that a decommissioning EP will be

submitted prior to the decommissioning activities commencing.1342

1332 Submission to the Legislative Council Standing Committee on Environment and Public Affairs, Parliament

of Western Australia, Inquiry into the Implications for Western Australia of Hydraulic Fracturing for

Unconventional Gas, Department of Mines and Petroleum 2013, p 16 at

<http://www.parliament.wa.gov.au/Parliament/commit.nsf/(Evidence+Lookup+by+Com+ID)/C4EBD44EB7D

29B4848257C40000F2471/$file/ev.fra.131003.sub.105.department+of+mines+and+petroleum.pdf> 1333 Department of Mines, Industry Regulation and Safety, Guide to the Regulatory Framework for Shale and

Tight Gas in WA, A Whole of Government Approach, 2015 Edition, pg 31 at <

http://www.dmp.wa.gov.au/Documents/Petroleum/WEB_Shale_and_Tight_Gas_Framework.pdf> 1334 Buru Energy, Canning Basin Well Drilling Environment Plan Summary Document, 2013, pg 11 at

<http://www.buruenergy.com/wp-content/uploads/Canning-Basin-Well-Drilling-Environment-Plan.pdf> 1335 Ibid. 1336 Ibid. 1337 Buru Energy, Jackaroo 1 and Victory 1 Well Drilling Environment Plan Bridging Document: Summary

Document, 2015 at http://www.buruenergy.com/wp-content/uploads/HSE-SUM-021_Jackaroo-1-and-Victory-

1-Well-BD-Summary-Doc.pdf 1338 Id at 4. 1339 Ibid. 1340 Ibid. 1341 Department of Mines and Petroleum, Guide to the Regulatory Framework for Shale and Tight Gas in WA,

A Whole of Government Approach, 2015 Edition, pg 21 at

<http://www.DMIRS.wa.gov.au/Documents/Petroleum/WEB_Shale_and_Tight_Gas_Framework.pdf> 1342 Department of Mines and Petroleum, Guideline for the Development of Petroleum and Geothermal

Environment Plans in Western Australia, November 2016, pg 14

194

WMPs1343 must contain well abandonment and decommissioning information, field closure

plans and details about rehabilitation.1344 A WMP that fails to detail the risks associated with

abandonment will be rejected by the DMIRS (WA) (delaying the commencement of activities)

and reassessed if additional information is requested.1345 An activity program that describes

the process; that contains pre- and post-decommissioning diagrams; justifies if a well is no

longer economically viable and provides information in relation to wellhead removal and

regeneration of the site must also be lodged.1346 An operator wishing to decommission a well

must insulate the production zone with a cement plug1347 and place barriers in the well casing

to prevent fluids from entering or exiting the well once the wellhead is disconnected.1348 A

WMP must identify the risks to well integrity and set out in some detail how an operator intends

to manage risk in accordance with sound engineering principles, codes, standards and

specifications.1349

A FMP must provide an account of the life cycle of a project covered by a production licence

and typically include decommissioning and rehabilitation processes following completion of

resource extraction.1350 It must include a description of an operators plan for field closure1351

and describe the lifecycle of a project covered by an operator’s production licence and how the

project will be managed.1352 A FMP must list the aquifers that may be affected by exploration

and production, baseline monitoring of groundwater sources, information about proposed

1343 Petroleum and Geothermal Energy Resources (Resource Management and Administration) Regulations

2015 (WA), Part 3 1344 Petroleum and Geothermal Energy Resources (Resource Management and Administration) Regulations

2015 (WA), Schedule 1 and 3 1345 Department of Mines and Petroleum, Guidelines for the Petroleum and Geothermal Energy Resources

(Resource Management and Administration) Regulations 2015 and Petroleum (Submerged Lands) (Resource

Management and Administration) Regulations 2015, , p 23 at

<http://www.DMIRS.wa.gov.au/Documents/Petroleum/PD-SBD-ADM-180D.pdf> 1346 Department of Mines, Industry Regulation and Safety, Western Australia’s Petroleum and Geothermal

Explorer’s Guide, 2014 Edition, pg 109 at < http://www.dmp.wa.gov.au/Documents/Petroleum/PD-RES-PUB-

100D.pdf> 1347 Department of Mines, Industry Regulation and Safety, Guide to the Regulatory Framework for Shale and

Tight Gas in WA, A Whole of Government Approach, 2015 Edition, pg 31 at

<http://www.dmp.wa.gov.au/Documents/Petroleum/WEB_Shale_and_Tight_Gas_Framework.pdf> 1348 Id at 21. 1349 Id at 31. 1350 Id at 40. 1351 Petroleum and Geothermal Energy Resources (Resource Management and Administration) Regulations

2015 (WA), Schedule 3, Item 16 1352 Department of Mines, Industry Regulation and Safety, Guide to the Regulatory Framework for Shale and

Tight Gas in WA, A Whole of Government Approach, 2015 Edition, pg 31 at

http://www.dmp.wa.gov.au/Documents/Petroleum/WEB_Shale_and_Tight_Gas_Framework.pdf>

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injection of the resource or of water into underground formations and descriptions of an

operator’s plans for closure of the field and decommissioning and rehabilitation.1353

Operators must submit final well activity reports1354 which include the status of wells, that is,

whether they are producing, suspended or decommissioned1355 and if applicable, information

on cementing operations and schematics of decommissioning.1356 A well completion form1357

is also required, which includes the status of a well1358 and (if applicable) information on

cementing operations and schematics of decommissioning.1359 If a field is being

decommissioned, an operator must lodge a field decommissioning plan as part of the FMP

specifying the decommissioning procedure and a description of the decommissioning of the

wells, including removal of the wellheads.1360

4.4.2 South Australia – SEO

The PGEA refers to ‘decommissioning, abandonment and rehabilitation’.1361

Decommissioning, abandonment and rehabilitation in South Australia are carried out in

accordance with SEOs.1362 An operator who undertakes drilling must provide specific details

of well completion or abandonment.1363 Operators must not plug, backfill or seal a well unless

authorised to do so by a water management authorisation or permit.1364 The NRMA stipulates

1353 Petroleum and Geothermal Energy Resources (Resource Management and Administration) Regulations

2015 (WA), r 43 1354 Petroleum and Geothermal Energy Resources (Resource Management and Administration) Regulations

2015 (WA), r 73(1) 1355 Petroleum and Geothermal Energy Resources (Resource Management and Administration) Regulations

2015 (WA), Schedule 7, Item 5 1356 Petroleum and Geothermal Energy Resources (Resource Management and Administration) Regulations

2015 (WA), Schedule 7, Item 22 1357 Petroleum and Geothermal Energy Resources (Resource Management and Administration) Regulations

2015 (WA), r 74(1) 1358 Petroleum and Geothermal Energy Resources (Resource Management and Administration) Regulations

2015 (WA), Schedule 9, Item 6 1359 Petroleum and Geothermal Energy Resources (Resource Management and Administration) Regulations

2015 (WA), Schedule 9, Item 30 1360 Department of Mines and Petroleum, Western Australia’s Petroleum and Geothermal Explorer’s Guide,

2014 Edition, pg 109 at <http://www.DMIRS.wa.gov.au/Documents/Petroleum/PD-RES-PUB-100D.pdf> 1361 Petroleum and Geothermal Energy Act 2000 (SA) and Petroleum and Geothermal Energy Regulations 2013

(SA) 1362 Petroleum and Geothermal Energy Regulations 2013 (SA), r 13(1)(e) 1363 Petroleum and Geothermal Energy Regulations 2013 (SA), r 40(2)(n)

1364 Natural Resources Management Act 2004 (SA), s 127

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that it is a condition of a permit to plug, backfill or seal a well or to repair, replace or alter the

casing, lining or screen of a well that the work be undertaken by licensed well driller or is

supervised by a licensed well driller.1365 The term of an associated activities licence for

regulated activities may take may take into account any decommissioning, rehabilitation or

other action that may be required at the conclusion of the activities.1366

An SEO is prepared on the basis of an Environmental Impact Report (EIR).1367 An SEO and

EIR must address potential impacts on aquifers, including contamination; impacts on

groundwater use; surface water use, shallow groundwater and water storage ponds.1368 Santos’

Cooper Basin SEO1369 deals with well and zonal decommissioning1370 and rehabilitation.1371

Rehabilitation is carried out in accordance with environmental objective six which relates to

minimising loss of aquifer pressure and the avoidance of aquifer contamination.1372 To achieve

objective six the SEO states that solation barriers must be in place to ensure that crossflow,

contamination or pressure reduction does not occur; barriers must meet or exceed the

requirements of applicable standards for the decommissioning of petroleum wells; and

isolation barriers should be placed to isolate the groups of formations. The number may be

varied from the standard approach on a case-by-case basis and in consultation and or with

approval from DPC.1373

Santos’ Cooper Basin EIR1374 sets out the events that are reasonably foreseeable and that

could pose a threat to the environment (including events during decommissioning).1375 Where

a well or zone needs to be decommissioned, specific aspects of the well must be considered

1365 Natural Resources Management Act 2004 (SA), s 135(11)

1366 Petroleum and Geothermal Energy Act 2000 (SA), s 58(2) 1367 Id section 97. 1368 Department of Statement Development, Statement of Environmental Objectives, (accessed 18 June 2017)

<http://petroleum.statedevelopment.sa.gov.au/legislation/regulation/seo> 1369 Santos, SA Cooper Basin, Statement of Environmental Objectives: Drilling, Completions and Well

Operations, November 2015 at

<https://sarigbasis.pir.sa.gov.au/WebtopEw/ws/samref/sarig1/image/DDD/PGER00246SEO%20DRILLING%

20OPERATIONS.pdf> 1370 Id at 4. 1371 Id at 7. 1372 Ibid. 1373 Id at 13. 1374 Santos, SA Cooper Basin, Environmental Impact Report: Drilling, Completions and Well Operations,

November 2015 at

<https://sarigbasis.pir.sa.gov.au/WebtopEw/ws/samref/sarig1/image/DDD/PGER00245EIR%20DRILLING%2

0OPERATIONS.pdf> 1375 Id at 6.

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when developing an appropriate decommissioning procedure.1376 The EIR classifies wells as;

cased and suspended (C&S), producing, decommissioned and suspended/inactive.1377

Decommissioning of the well bore and surface infrastructure commences once production

infrastructure and facilities have been removed.1378

When drilling is complete, well testing is carried out to determine production potential and a

judgement is made about whether to run a cement production casing or plug and decommission

the well.1379 If a well is plugged, the drilling string1380 is removed from the hole and the

production casing is run into the well bore and cemented in place.1381 When an operator plugs

and decommissions a well, consideration is given to isolating all formations that contain gas;

isolating Permian formations from Jurassic aquifers; setting plugs across intermediate casing

shoe (if present) to minimise the potential for cross flow between aquifers and gas bearing

intervals as defined in the SEO; setting plugs across surface casing shoe; and at the surface set

a plug in the well prior to cutting off the surface casing bowl.1382

Where issues are discovered regarding casing or cement, hydraulic fracturing is suspended

until the well is remediated.1383 If it is determined that remediation of the well is physically or

economically non-viable, the well is completed without hydraulic fracturing, or plugged and

decommissioned in accordance with best practices and regulatory requirements.1384 The object

of well decommissioning is to separate gas and water bearing formations.1385

1376 Ibid. 1377 Id at 9. 1378 Id at 15. 1379 Id at 19. 1380 Schlumberger, Oilfield Glossary, ‘Drill String’, (accessed 20 May 2017) at

http://www.glossary.oilfield.slb.com/Terms/d/drill_string.aspx 1381 Santos, SA Cooper Basin, Environmental Impact Report: Drilling, Completions and Well Operations, pg

53, November 2015 at

<https://sarigbasis.pir.sa.gov.au/WebtopEw/ws/samref/sarig1/image/DDD/PGER00245EIR%20DRILLING%2

0OPERATIONS.pdf> 1382 Id at 19. 1383 Id at 53. 1384 Ibid. 1385 Ibid.

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4.4.3 Colorado – Reclamation regulations

The OGCA refers ‘abandonment and reclamation’.1386 Plugging and abandonment denotes

‘the cementing of a well, the removal of its associated production facilities, the removal or

abandonment in-place of its flowline, and the remediation and reclamation of the well site.’1387

Operators must submit a well abandonment report form to the COGCC,1388 a ‘Notice of Intent

to Abandon’ and ‘Subsequent Report of Abandonment’.1389

The COGCC rules ‘establish the proper reclamation of the land and soil affected by oil and gas

operations and ensure the protection of the topsoil of said land during such operations.’1390 The

surface of the land shall be restored as nearly as practicable to its condition at the

commencement of drilling operations.1391

In order to reduce land disturbance and to facilitate future reclamation ‘well sites, production

facilities, gathering pipelines, and access roads shall be located, adequately sized, constructed,

and maintained so as to reasonably control dust and minimize erosion, alteration of natural

features, removal of surface materials, and degradation due to contamination.’1392

The COGCC rules set out that roads must be used to avoid erosion and minimise the land area

devoted to gas operations and roadbeds must be engineered to avoid or minimise impacts to

riverbanks or wetlands to the extent possible.1393

1386 COGCC series 300 rules (drilling, development, production and abandonment) and its 1000 rules

(Reclamation Regulations) 1387 COGCC rules, definitions 1388 COGCC Form 6, Well Abandonment Report at

<http://cogcc.state.co.us/documents/reg/Forms/PDF_Forms/form6.pdfhttp://cogcc.state.co.us/documents/reg/F

orms/PDF_Forms/form6.pdf> 1389 COGCC Form 6, Well Abandonment Report at

<http://cogcc.state.co.us/documents/reg/Forms/PDF_Forms/form6.pdf> 1390 COGCC rule 1001 (Reclamation Regulations) at

https://cogcc.state.co.us/documents/reg/Rules/LATEST/1000Series.pdf 1391 COGCC rule 1001 (Reclamation Regulations) at

https://cogcc.state.co.us/documents/reg/Rules/LATEST/1000Series.pdf 1392 COGCC rule 1002.e.(1) at https://cogcc.state.co.us/documents/reg/Rules/LATEST/1000Series.pdf 1393 COGCC rule 1002.e.(4) at https://cogcc.state.co.us/documents/reg/Rules/LATEST/1000Series.pdf

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In Colorado, an operator must provide details of proposed abandonment operations to the

COGCC.1394 They must outline the anticipated depths of mechanical plugs and casing cuts,

the anticipated depths and volumes of all cement plugs, the amount, size and depth of casing

and junk to be left in the well, the volume, weight, and type of fluid to be left in the wellbore

between cement or mechanical plugs and the nature and quantities of any other materials to be

used in the plugging.1395 Operators must provide a current wellbore diagram and a wellbore

diagram showing the proposed plugging procedure.1396

When preparing for final reclamation, plugging and abandonment operators must use their best

efforts to consult in good faith with surface owners (or tenants).1397 Operators must aim to give

surface owners (or there appointed agent) the chance to provide feedback in relation to the

timing of operations and on final reclamation, including the desired final land use and seed mix

to be applied.1398 An operator who wishes to abandon a well must comply with specific

regulatory requirements, contractual obligations, and lessor and landowner requirements.1399

Following abandonment, operators must provide an account of the manner in which it was

performed, casing pressure test results and downhole logs runs.1400 Operators must provide

plugging verification reports which specify the depths of mechanical plugs and casing cuts, the

depths and volumes of all cement plugs, the amount, size and depth of casing and ‘junk’ left in

the well, the volume and weight of fluid left in the wellbore and the nature and quantities of

any other materials used in the plugging.1401 An operator must notify the COGCC prior to re-

entering a plugged and abandoned well for the purpose of re-plugging the well.1402

To protect fresh water strata, no surface casing is to be removed from a well unless an operator

receives authorisation from the COGCC.1403 An operator must obtain prior approval of the

1394 COGCC rule 311(a) and COGCC Form 6, Well Abandonment Report at

<https://cogcc.state.co.us/documents/reg/Forms/PDF_Forms/form6.pdf> 1395 COGCC rule 311(a) at https://cogcc.state.co.us/documents/reg/Rules/LATEST/300Series.pdf 1396 COGCC rule 311(a) at https://cogcc.state.co.us/documents/reg/Rules/LATEST/300Series.pdf 1397 COGCC rule 306.e.f at https://cogcc.state.co.us/documents/reg/Rules/LATEST/300Series.pdf 1398 COGCC rule 306.e.f at https://cogcc.state.co.us/documents/reg/Rules/LATEST/300Series.pdf 1399 API, Environmental Protection for Onshore Oil and Gas Production Operations and Leases, API

Recommended Practice 51R, First Edition, July 2009, pg 11 at

<http://www.api.org/~/media/Files/Policy/Exploration/API_RP_51R.pdf> 1400 COGCC rule 311(b) at https://cogcc.state.co.us/documents/reg/Rules/LATEST/300Series.pdf 1401 COGCC rule 311(b) at https://cogcc.state.co.us/documents/reg/Rules/LATEST/300Series.pdf 1402 COGCC rule 311(c) at https://cogcc.state.co.us/documents/reg/Rules/LATEST/300Series.pdf 1403 COGCC rule 319(a)(4) at https://cogcc.state.co.us/documents/reg/Rules/LATEST/300Series.pdf

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plugging method and advise the COGCC of the estimated time and date of plugging and

identify the depth and thickness of all known sources of groundwater.1404 All access roads to

plugged and abandoned wells and related production facilities must be closed, graded and re-

contoured. 1405

In Colorado, surface land must be restored to the condition it was in at the start of the drilling

operation1406 i.e., disturbed areas no longer needed must be restored and revegetated as soon as

practicable.1407 The COGCC rules set out that operators should locate, construct and maintain

well sites, production facilities, gathering pipelines, and access roads to satisfactorily control

dust and minimise erosion, alteration of natural features, removal of surface materials, and

degradation due to contamination.1408 Those areas affected by drilling or subsequent

operations, excluding ones that are needed for production purposes or for subsequent drilling

operations commencing within twelve months, must be reclaimed to their previous condition

or in a way that makes them suitable for their final land use as chosen by the landowner and

must be maintained to control dust and minimize erosion to a level that is practicable.1409

The plugging, sealing and abandonment of wells is required to avoid contamination of ground

water and the migration of water through a well’s borehole.1410 A well owner is responsible

for having an existing well properly plugged, sealed and abandoned.1411 Moreover, a well

construction contractor or authorised person is responsible for informing the well owner in

writing of these plugging requirements.1412

1404 COGCC rule 319(a)(6) at https://cogcc.state.co.us/documents/reg/Rules/LATEST/300Series.pdf 1405 COGCC rule 1004(a) at https://cogcc.state.co.us/documents/reg/Rules/LATEST/1000Series.pdf 1406 COGCC rule 1001(a) at https://cogcc.state.co.us/documents/reg/Rules/LATEST/1000Series.pdf 1407 COGCC rule 1003(e) at https://cogcc.state.co.us/documents/reg/Rules/LATEST/1000Series.pdf 1408 COGCC rule 1001(e)(1) at https://cogcc.state.co.us/documents/reg/Rules/LATEST/1000Series.pdf 1409 COGCC rule 1003(b) at https://cogcc.state.co.us/documents/reg/Rules/LATEST/1000Series.pdf 1410 Rule 16 of the Water Well Construction Rules at http://water.state.co.us/DWRIPub/Documents/gws-

09.pdf 1411 Rule 16 of the Water Well Construction Rules at http://water.state.co.us/DWRIPub/Documents/gws-

09.pdf 1412 Rule 16 of the Water Well Construction Rules at http://water.state.co.us/DWRIPub/Documents/gws-

09.pdf

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4.4.4 Conclusion

The author contends that the PGERA and PGERA should require operators to carry out

decommissioning and rehabilitation in a similar vein to the COGCC rules. Western Australia

and South Australia do not treat abandonment and reclamation in the same way as Colorado.

These activities are not considered petroleum operations under the PGERA or regulated

activities under the PGEA. By comparison they are deemed oil and gas operations under the

OGCA. It is concerning that the PGERA does specifically refer to decommissioning and

rehabilitation and the PGEA to decommissioning, abandonment and rehabilitation. The

COGCC rules deal extensively with abandonment and reclamation.

The author favours Colorado’s approach where specific details of proposed abandonment

operations must be provided to the COGCC. The PGERA and PGEA should include specific

provisions that deal with the relationship between landowners and operators with respect to

decommissioning and rehabilitation as is the case in Colorado where operators must use their

best efforts to consult in good faith with surface owner which gives surface owners the chance

to provide feedback on the timing of operations and on final reclamation, including the desired

final land use and seed mix to be applied. An operator abandoning a well in Colorado must

comply with specific regulatory requirements, contractual obligations, and lessor and

landowner requirements. There are no lessor and landowner requirements in the PGERA or

PGEA.

The author favour Colorado’s approach where operators submit three straight forward reports

that deal with well abandonment, a well abandonment report, abandonment intention report

and a report after abandonment has occurred. The PGERA and PGEA are silent on the

protection of fresh water strata in terms of decommissioning and rehabilitation. The COGCC

must authorise the removal of surface casing from wells COGCC. The COGCC rules explicitly

state that surface land must be restored to the condition it was at the start of the drilling

operation them suitable for their final land use as chosen by the landowner and must be

maintained to control dust and minimise erosion to a level that is practicable.

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5 CONCLUSION AND RECOMMENDATIONS

5.1 Introduction

The production of shale and tight gas globally has been characterised by:

… a tendency for all stakeholders to assume that old oil and gas regulations are good

enough, because they have worked in the past. But, as we have seen, shale gas

development, particularly its rapid pace and large scale, brings with it new risks, and new

variations of old risks. These new and different risks do not necessarily mean that

development should stop. But, it is critical that all stakeholders commit to continued

discussion of risks, and policies that might address them.1413

Australia has the potential to follow the U.S and become one of the largest producers of shale

and tight gas in the world, given that it reportedly holds 437 trillion cubic feet (tcf) of

technically recoverable shale gas. The Canning Basin, located in Western Australia is reported

to contain 235 tcf or roughly double the amount of gas held in the state’s offshore conventional

fields. By comparison the U.S. reportedly holds 610 tcf of technically recoverable shale gas.

The significant increase in shale and tight gas production in the United States over the last

decade has fuelled debate about the effectiveness of regulatory regimes to deal with access to

land, drilling, water exploitation and post tenure liability. The thesis has undertaken a

comparative analysis of how Western Australia, South Australia and Colorado have addressed

each of these regulatory issues. That analysis leads to the following recommendations for

reform for Australian jurisdictions’ regulatory frameworks.

1413 Rahm, B, G and Riha, S, J, Evolving shale gas management: water resource risks, impacts, and lessons

learned, Environ. Sci: Processes Impacts, 2014, 16, 1400, page 1409 at

http://pubs.rsc.org/en/content/articlepdf/2014/EM/C4EM00018H

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5.2 Recommendations

Recommendation 1

The author recommends that Western Australia and South Australia consider inserting a

reasonable accommodation provision (similar to the OGCA) into the PGERA and PGEA.

This provision would be an entirely new feature and require operators to carry out shale and

tight gas exploration, production and abandonment activities in a way that supports surface

owners and reduces disturbance upon and damage to surface lands.

Recommendation 2

Western Australia and South Australia should develop statutory frameworks for land access

agreements. In the absence of this, their respective land access agreement templates should be

amended to:

a) protect landowners from having their entire property held under a lease when shale and

tight gas production is taking place on a very small section;

b) specify the location of wells given that drilling pads can be located some distance away

from gas deposits;

c) outline the frequency of an operator’s entry to a landowner’s property and, after a well

is drilled, consideration should be given to the frequency of monitoring;

d) deal with surface disturbance, interim reclamation, pits, waste disposal, groundwater

impacts, noise impacts, dust impacts visual impacts, water rights, fencing, damage,

timing of operations and current land use;

e) specify whether operators intend to co-locate wells on single well pads to minimise

surface impacts; and

f) set out a negotiation process that deals with the location of roads and vehicle access; in

particular, whether there is an intention to construct temporary roads and a process for

the negotiating transport plans.

204

Recommendation 3:

The author recommends that the DMIRS adopt the DPC’s approach to environmental

management given the PGEA has a much more robust environmental management regime than

the PGERA. Consideration should be given to amending the PGERA environmental plan to

mirror the PGEA’s SEO.

SEOs go far beyond what is needed in an EP under the PGERA. For example, SEOs explicitly

address impacts on aquifers, impacts on groundwater use, contamination of surface water and

shallow groundwater, water storage ponds, flow-back storage ponds and rehabilitation. EPs

do not do this to the same extent.

Recommendation 4:

The author recommends that the PGERA and PGEA should be amended to include provisions

that set internal, intermediate, and external buffer areas to protect surface waters in and around

the Canning Basin and Cooper Basins. The author suggests that this would safeguard surface

public water sources through additional protections when gas facilities are situated close to

designated surface water sources. It would also prevent gas facilities from being located within

a certain distance from designated water sources.

Recommendation 5:

The author recommends the insertion of a provision in PGERA and PGEA to allow operators

to lodge voluntary comprehensive drilling plans. These plans would ensure that anticipated

gas activities are identified and that there is a discussion about potential impacts and the

identification of measures to reduce adverse impacts to the environment. The DMIRS and

DPC should encourage operators to liaise with their respective EPAs and surface owners to

compile these plans.

205

Recommendation 6:

The author recommends that the PGERA and PGEA should be amended to include provisions

for a baseline and post-completion groundwater monitoring regimes similar to that which exists

in the COGCC rules. The DMIRS and DPC should follow the COGCC’s lead and implement

rules dealing with cement bond logs, mechanical integrity tests and bradenhead tests. These

are all critically important for safeguarding a well’s integrity.

Recommendation 7:

The author supports, as a bare minimum, the introduction of baseline water sampling in the

Canning Basin and Cooper Basin. This is consistent with the approach taken in Colorado’s

Greater Wattenberg Area. It is makes regulatory sense to ensure monitoring is carried out

where most gas production occurs.

Recommendation 8:

The author recommends that Western Australia and South Australia implement restrictive

stormwater rules applicable to shale and tight gas activities. Both jurisdictions should develop

their own best management practices and database for shale and tight gas development.

Recommendation 9:

The author favours well setback rules that exist in Colorado. These rules ensure precautions

are taken near surface waters used for drinking. It also favours its pit permitting and reporting

requirements and pit lining requirements. The COGCC rules require that spills and releases

are reported to the COGCC, CDPHE and the landowner.

Recommendation 10:

The author recommends that the DMIRS and DPC actively encourage and promote the

reduction of waste by allowing operators to submit management plans that deal with

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beneficial use, reuse and recycling. The author favours the COGCC underground injection

authorisation regime.

Recommendation 11:

The author favours Colorado’s chemical disclosure system where operators complete a

chemical disclosure registry form and upload it onto FracFocus. Any information that is posted

to the site or sent to the COGCC (unless a trade secret) is public information. The COGCC

and the public can search for information by geographic area, ingredient, chemical abstract

service number, time period, and operator.

Recommendation 12:

The author favours Colorado’s chemical disclosure system where operators submit chemical

disclosure forms within 60 days of the conclusion of hydraulic fracturing. The author also

favours the approach whereby operators who claim that the identity or concentration of a

chemical is a trade secret do not need to disclose them on their disclosure form, though the

information must be provided to the COGCC if it is requested.

Recommendation 13:

The author recommends the DMIRS and DPC include in the PGERA and PGEA preliminary

baseline sampling and subsequent monitoring requirements where all available water sources

within 800 metres of a proposed gas well, multi-well site, or dedicated injection well. The

author recommends subsequent sampling is carried out at the initial sample locations and

subsequent sampling is conducted following completion of the well or dedicated injection well

or the last well on a multi-well site.

Recommendation 14:

The absence in the PGERA and PGEA of a legal statement regarding decommissioning and

reclamation is not ideal. The PGERA should be amended to include decommissioning and the

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PGEA to decommissioning, abandonment and rehabilitation. The COGCC rules deal

extensively with abandonment and reclamation.

Recommendation 15:

The author favours Colorado’s best efforts approach. There are no specific provisions in the

PGERA or PGEA that deal with the relationship between landowner and operators with respect

to decommissioning and rehabilitation. By comparison, the COGCC rules require operators to

use their best efforts to consult in good faith with surface owner, which gives surface owners

the chance to provide feedback on final reclamation.

Recommendation 16:

The author favours Colorado’s command and control approach to regulation, at least in the

early stages of Western Australia’s and South Australia’s journey to exploiting shale and

tight gas. This approach will likely alleviate the some of the concerns of held by those

vehemently opposed it.

5.3 Summary of Key Issues

This section summarises the gaps that this thesis contends exist in Western Australia and South

Australia in relation to the exploitation of shale and tight gas and land access, water access and

quality protection, regulation of well technology for drilling and hydraulic fracturing and

decommissioning and associated issues.

Regulating the exploitation of shale and tight gas is a difficult task for governments and by

implication for the regulatory bodies that are tasked with turning these policies into regulatory

regimes. Ultimately, regulatory regimes will be judged by communities and they will either

be supported or rejected. Wide spread discontent can result in bans and moratoria.

This current angst with exploiting shale and tight gas in Western Australia and, to a lesser

extent, South Australia is largely due to concerns about land access and the complex

exploration and production techniques required to facilitate extraction, the evolving

208

understanding of risks and challenges by some jurisdictions and the rapid pace of development.

The arid conditions in the Canning Basin and Cooper Basin could result in considerable

exploration, production and abandonment challenges. A particular issue will be water resource

management.

Large amounts of water are needed to exploit shale and tight gas through the use of horizontal

drilling and hydraulic fracturing. The use of both of these techniques in the United States has

resulted in an average annual growth rate of nearly 50 per cent in shale gas production.1414

Western Australia and South Australia will need to deal with water sustainability;

contamination and competition issues that will overshadow other environmental issues in their

pursuit of shale and tight gas.

The water required for shale and tight gas production in Western Australia and South Australia

will be surface water (streams, ponds or lakes); groundwater (aquifers) or water from

alternative sources (drainage water, from recycling or transported by truck or rail). A

developed industry located in or around the Canning Basin (WA) or Cooper Basin (SA) – both

arid areas - will be a significant exploiter of groundwater relative to sustainable extraction

levels.

Shale and tight gas reserves located in arid regions and producers may be have to rely solely

on groundwater to undertake hydraulic fracturing, in fact groundwater will likely be the only

water available in some areas. Where groundwater recharge rates are low there will be

challenges for both operators and regulators.

The negative impacts on water resources could, if not appropriately managed, cause

environmental and production issues beyond immediate production areas. The author rejects

the notion that the rapidity of change in the shale and tight gas industry has often outpaced the

availability of information for regulators to develop specific guidance. This defence for simply

overlooking regulatory gaps should not be used.

1414 Unconventional Gas Production and Water Resources, Lessons from the United States on better governance

– a workshop for Australian government officials, Crawford School of Public Policy, 2012, pg 6 at

https://crawford.anu.edu.au/pdf/inthenews/12186-unconventional-gas-document-web-fa.PDF

209

This thesis favours a number of the approaches taken to shale and tight gas development in

Colorado over the approaches currently taken in Western Australia and South Australia. With

respect, the PGERA and PGEA lack a number of pre-emptive sections to deal with issues that

will likely face shale and tight gas operators in Western Australia and South Australia

respectively. Western Australia and South Australia have been largely reactive in regulating

and though they are in the early stages of exploration and full scale production, this is not a

satisfactory justification.

Colorado has an embedded regulatory framework and is in the advanced stage of shale gas

development, with all their elements operating as a system. With respect, Western Australia

(and to a lesser extent South Australia) is playing a game of ‘follow the leader’ and ‘regulatory

catch-up’. Neither has kept pace with the significant risks and challenges linked to shale and

tight gas development. The OGCA and COGCC rules should be used to amend the PGERA

and PGEA.

This thesis favours South Australia’s regulatory approval process over that of Western

Australia. A PGEA exploration licence application must include a prospectivity assessment

and an outline how the proposed work program relates to it this assessment. There is no

requirement under the PGERA for operators to assess prospectivity when they apply for an

exploration permit.

This thesis favours Colorado’s permit to drill application, given that it specifies the distance

between the well and wall or corner of the nearest building, public road, above ground utility,

railroad, and property line. This is vastly different to the PGERA and PGEA, where there no

requirement to consider anything other than the resources being targeted for exploration and

production.

This thesis favours the PGEA’s consultation requirements over those in the PGERA. In South

Australia, stakeholders, including landholders, must be informed and advised on the potential

risks associated with proposed activities, and the management strategies that will be used to

minimise risk. They must also be provided with the opportunity to raise any issues of concern

before regulated activities commence. The DPC expects that licensees will consult

stakeholders prior to and during the development of their EIR and SEO, to describe their

activities and the potential impacts which may be experienced.

210

The PGEA also has a much more robust environmental management regime than the PGERA.

Although the PGERA requires an operator to describe the regulated activities they intend to

undertake and provide information about environmental impacts and risks from exploitation to

the existing environment, and requires a risk assessment process be used to evaluate those

impacts and risks, this information is only provided prior to the regulated activities being

carried out and does not include any detail after they have been completed. In setting out how

land adversely affected by regulated activities will be rehabilitated, an SEO goes far beyond

what is needed in an EP. SEOs explicitly address impacts on aquifers, impacts on groundwater

use, contamination of surface water and shallow groundwater, water storage ponds, flow-back

storage ponds. EPs do not do so to the same extent.

If Western Australia’s current ban and moratoria on exploiting shale and tight gas is lifted, the

author recommends that the DMIRS adopt a command and control approach in the short term.

Command and control is ideal for the early stages of regulatory intervention. This may alleviate

some of the concerns held by those vehemently opposed to it. This approach will allow the

DIMRS to set clear limits and to administer them within a legislative framework. The author

does not believe that using a command and control approach will result in community

disengagement or operator distrust. Implementing a command and control approach may

provide a satisfactory basis for the industry to gain a social licence to operate.

211

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